Atlas pipelinehos1[1]

FORM S−1Atlas Pipeline Holdings, L.P. − AHD

Filed: January 12, 2006 (period: )

General form of registration statement: Initial statement

Table of Contents

PART I

INFORMATION REQUIRED IN PROSPECTUSSUMMARYRISK FACTORSUSE OF PROCEEDSCAPITALIZATIONMANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONAND RESULTS OF OPERATIONSBUSINESSPropertiesMANAGEMENTSECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS ANDMANAGEMENTCERTAIN RELATIONSHIPS AND RELATED TRANSACTIONSUNDERWRITINGEXPERTSINDEX TO FINANCIAL STATEMENTSRelated Party TransactionsRelated Party Transactions

PART II

Item 13. Other Expenses of Issuance and Distribution.Item 14. Indemnification of Officers and Members of Our Board of Directors.Item 15. Exhibits.Item 16. Undertakings.SIGNATURESEX−23.1 (EXHIBIT 23.1)

EX−23.2 (EXHIBIT 23.2)

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As filed with the Securities and Exchange Commission on January 12, 2006

Registration No. 333−

UNITED STATESSECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S−1REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Atlas Pipeline Holdings, L.P. (Exact Name of Registrant as Specified in Its Charter)

Delaware(State or Other Jurisdiction of

Incorporation or Organization)

1311(Primary Standard IndustrialClassification Code Number)

Applied For(I.R.S. Employer

Identification Number)

Edward E. Cohen311 Rouser Road

Moon Township, PA 15108(412) 262−2830

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant's Principal Executive Offices)

Edward E. Cohen311 Rouser Road

Moon Township, PA 15108(412) 262−2830

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:

Alan P. BadenVinson & Elkins L.L.P.

666 Fifth AvenueNew York, New York 10103

(212) 237−0000

Joshua DavidsonBaker Botts L.L.P.

910 Louisiana StreetHouston, Texas 77002

(713) 229−1234

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933,check the following box.

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list theSecurities Act registration statement number of the earlier effective registration statement for the same offering.

If this form is a post−effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Actregistration statement number of the earlier effective registration statement for the same offering.

If this form is a post−effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Actregistration statement number of the earlier effective registration statement for the same offering.

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.

CALCULATION OF REGISTRATION FEE

Title Of Each Class OfSecurities To Be Registered

Proposed Maximum AggregateOffering Price (1)(2)

Amount ofRegistration Fee

Common units representing limited partner interests $ 103,500,000 $ 11,074.50

(1) Includes common units issuable upon exercise of the underwriters'optionto acquire additional common units.

(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrantshall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a)of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting

Source: Atlas Pipeline Holdi, S−1, January 12, 2006

pursuant to said Section 8(a), may determine.


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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and ExchangeCommission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is notpermitted.

Subject to Completion, dated January 12, 2006

PROSPECTUS

ATLAS PIPELINE HOLDINGS, L.P.

3,600,000 Common Units

Representing Limited Partner Interests

This is the initial public offering of our common units. We own a 2.0% general partner interest, all the incentive distribution rights and an approximate 12.8%limited partner interest in Atlas Pipeline Partners, L.P., a midstream energy services provider engaged in the transmission, gathering and processing of naturalgas.

Before this offering, there has been no public market for our common units. We intend to apply to list the common units on the New York Stock Exchange underthe symbol “ .” We expect the initial public offering price to be between $ and $ per unit.

We will use substantially all of the net proceeds from this offering to make a cash distribution to our existing unitholders. Please read “Use of Proceeds.”

Investing in our common units involves risks. Please read “Risk factors” beginning on page 22.

These risks include the following:

• Our only cash generating assets are our interests in Atlas Pipeline Partners, L.P., and our cash flow is therefore completely dependent upon the abilityof Atlas Pipeline Partners, L.P. to make distributions to its partners.

• You will experience immediate and substantial dilution of $24.63 per common unit in the pro forma net tangible book value of your common units.

• If we or Atlas Pipeline Partners, L.P. were treated as a corporation for federal income tax purposes, or if we or Atlas were to become subject toentity−level taxation for federal or state income tax purposes, then our cash available for distribution to you would be substantially reduced.

• Our unitholders do not elect our general partner or vote on our general partner’s officers or directors, and the rights of unitholders owning 20% or moreof our units are further restricted under our partnership agreement. Following the completion of this offering, Atlas America, Inc. will ownapproximately 82.9% of our common units, a sufficient number to prevent removal of our general partner without its consent.

• The fiduciary duties of our general partner’s officers and directors may conflict with those of Atlas Pipeline Partners GP, LLC, which is the generalpartner of Atlas Pipeline Partners, L.P.

• You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Per Common Unit Total

Initial public offering price $ $Underwriting discount

(1)$ $

Proceeds to us, before expenses $ $

(1) Excludes structuring fee payable to Lehman Brothers Inc. of .

We have granted the underwriters a 30−day option to purchase up to an additional 540,000 common units from us on the same terms and conditions as set forthabove if the underwriters sell more than 3,600,000 common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon theadequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about , 2006.


LEHMAN BROTHERS

, 2006


We own and control Atlas Pipeline Partners GP, LLC, the general partner of Atlas Pipeline Partners, L.P. (NYSE: APL), through which we own certain generalpartner interests, all the incentive distribution rights and 1,641,026 common units of Atlas Pipeline Partners, L.P., representing an approximate 12.8% limitedpartner interest. We do not have any other assets. The map below identifies Atlas Pipeline Partners, L.P.’s operations and their location.

Atlas Pipeline Partners, L.P. Operations


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TABLE OF CONTENTS

SUMMARY 1Atlas Pipeline Holdings, L.P. 1The Offering 6Atlas Pipeline Partners, L.P. 8Atlas’ Principal Executive Offices and Internet Address 10Comparison of Rights of Holders of Our Common Units and Atlas’ Common Units 11Summary of Risk Factors 13Summary of Conflicts of Interest and Fiduciary Responsibilities 15Summary Historical Consolidated and Pro Forma Financial Data 16RISK FACTORS 22Risks Inherent in an Investment in Us 22Risks Related to Conflicts of Interest 31Risks Relating to Atlas’ Business 34Tax Risks to Common Unitholders 42USE OF PROCEEDS 45CAPITALIZATION 46DILUTION 47CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS 48General 48Our Initial Distribution Rate 50Estimated Cash Available for Distributions 56Assumptions and Considerations 59Our Sources of Distributable Cash 61SELECTED HISTORICAL AND OPERATING DATA 64MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 68Overview 68Atlas Pipeline Partners, L.P. 69Overview of Atlas’ Operations 69Significant Acquisitions 70Contractual Revenue Agreements 70Results of Our Operations 71Liquidity and Capital Resources 74Atlas Partnership Distributions 76Contractual Obligations and Commercial Commitments 77Atlas’ Equity Offerings 77Atlas’ Shelf Registration Statement 78Atlas’ Credit Facility 78NOARK Notes 79Significant Announced Internal Growth Project 79Environmental Regulation 79Inflation and Changes in Prices 80Critical Accounting Policies and Estimates 80Quantitative and Qualitative Disclosures About Market Risk 84BUSINESS 87Atlas Pipeline Holdings, L.P. 87Atlas Pipeline Partners, L.P. 90Overview 90Recent Acquisitions 91Business Strategy 92Competitive Strengths 93The Midstream Natural Gas Gathering, Processing and Transmission Industry 94Mid−Continent Operations 95Appalachian Basin Operations 99Relationship with Atlas America 100Competition 103Contracts and Customer Relationships 104Regulation 104Environmental Matters 106Employees 109Properties 109Legal Proceedings 110MANAGEMENT 111Atlas Pipeline Holdings, L.P. 111Board Committees 112Election of Our Directors 113Governance Matters 113Compensation of Directors 114Atlas Pipeline Holdings Long−Term Incentive Plan 114Compensation Committee Interlocks and Insider Participation 115Atlas Pipeline Partners, L.P. 116Executive Officer Compensation 117Long−Term Incentive Plan 118Compensation of Managing Board Members 118SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 119CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 120


Our Relationship with Atlas Pipeline Partners, L.P. 120The Contribution Agreement 120Registration Rights 120

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Indemnification of Directors and Officers 120Related Party Transactions Involving Atlas 121CONFLICTS OF INTEREST AND FIDUCIARY DUTIES 122Conflicts of Interest 122Fiduciary Duties 124DESCRIPTION OF THE COMMON UNITS 127The Units 127Transfer Agent and Registrar 127Transfer of Common Units 127THE PARTNERSHIP AGREEMENT OF ATLAS PIPELINE HOLDINGS, L.P. 129Organization and Duration 129Purpose 129Power of Attorney 129Capital Contributions 129Limited Liability 129Voting Rights 130Issuance of Additional Securities 131Amendments to Our Partnership Agreement 131Prohibited Amendments 132No Unitholder Approval 132Opinion of Counsel and Unitholder Approval 133Merger, Sale or Other Disposition of Assets 133Termination or Dissolution 133Liquidation and Distribution of Proceeds 134Withdrawal or Removal of Our General Partner 134Transfer of General Partner Interest 135Transfer of Ownership Interests in Our General Partner 135Change of Management Provisions 135Limited Call Right 135Meetings; Voting 136Status as Limited Partner 136Non−Citizen Assignees; Redemption 136Indemnification 137Reimbursement of Expenses 137Books and Reports 137Right to Inspect Our Books and Records 138Registration Rights 138THE PARTNERSHIP AGREEMENT OF ATLAS PIPELINE PARTNERS, L.P. 139Organization and Duration 139Purpose 139The Units 139Limited Voting Rights 139Cash Distribution Policy 139Power of Attorney 143Capital Contributions 144Limited Liability 144Transfer Agent and Registrar 144Transfer of Common Units 145Issuance of Additional Securities 146Amendment of Atlas’ Partnership Agreement 146Merger, Sale or Other Disposition of Assets of Atlas 148Termination and Dissolution 148Liquidation and Distribution of Proceeds 148Withdrawal or Removal of Atlas’ General Partner 148Transfer of General Partner Interest And Incentive Distribution Rights 150Change of Management Provisions 150Limited Call Right 150Meetings; Voting 150Status as Limited Partner or Assignee 151Non−Citizen Assignees; Redemption 151Indemnification 151Books and Reports 152Right to Inspect Our Books and Records 152Registration Rights 153UNITS ELIGIBLE FOR FUTURE SALE 154MATERIAL TAX CONSEQUENCES 155Partnership Status 155Limited Partner Status 156Tax Consequences of Unit Ownership 157Tax Treatment of Operations 162Disposition of Common Units 163Uniformity of Units 165Tax−Exempt Organizations and Other Investors 166Administrative Matters 166State, Local, Foreign and Other Tax Considerations 168INVESTMENT IN ATLAS PIPELINE HOLDINGS, L.P. BY EMPLOYEE BENEFIT PLANS 170UNDERWRITING 171Commissions and Expenses 171


Option to Purchase Additional Common Units 171Lock−Up Agreements 172Offering Price Determination 172Indemnification 172Directed Unit Program 172


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Stabilization, Short Positions and Penalty Bids 173Electronic Distribution 173NYSE 174Discretionary Sales 174Stamp Taxes 174Relationships 174VALIDITY OF THE COMMON UNITS 175EXPERTS 175WHERE YOU CAN FIND MORE INFORMATION 175FORWARD−LOOKING STATEMENTS 175INDEX TO FINANCIAL STATEMENTS F−1APPENDIX A — AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF ATLAS PIPELINE HOLDINGS, L.P. A−1

Until , 2006 (the 25th day after the date of this prospectus), all dealers that effect transactions in the securities, whether or not participating in thisoffering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and withrespect to their unsold allotments or subscriptions.

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide youwith different information from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not relyon it. We are not, and the underwriters are not, offering to sell our common units or seeking offers to buy our common units in any jurisdiction whereoffers or sales are not permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time ofdelivery of this prospectus or any sale of the common units offered hereby.

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SUMMARY

This summary may not contain all of the information that is important to you. You should read this entire prospectus carefully, including the historicalconsolidated financial statements and pro forma financial statements and the notes to those financial statements. Furthermore, you should carefully read“Summary of Risk Factors” and “Risk Factors” for more information about important risks that you should consider before making a decision to purchase ourcommon units.

Except as otherwise indicated, the information presented in this prospectus assumes (1) an initial public offering price of $24.00 per common unit and (2) thatthe underwriters do not exercise their option to purchase additional common units. All references in this prospectus to “we,” “our,” “us” or like terms refer toAtlas Pipeline Holdings, L.P., and unless the context requires otherwise, to Atlas Pipeline Partners GP, LLC, the general partner of Atlas Pipeline Partners, L.P.All references in this prospectus to “Atlas Pipeline GP” refer to Atlas Pipeline Partners GP, LLC. All references in this prospectus to “Atlas” refer to AtlasPipeline Partners, L.P. and its wholly−owned subsidiaries. All references in this prospectus to “Atlas America” refer to Atlas America, Inc. and itswholly−owned subsidiaries, excluding Atlas Pipeline Holdings, L.P. and any of its wholly−owned subsidiaries. All references to our “partnership agreement”refer to the Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P. to be adopted contemporaneously with the closing of thisoffering.

Atlas Pipeline Holdings, L.P.

Our cash generating assets consist of our interests in Atlas Pipeline Partners, L.P. (NYSE: APL), a publicly traded Delaware limited partnership. Atlas is amidstream energy service provider engaged in the transmission, gathering and processing of natural gas in the Mid−Continent and Appalachian regions. Ourinterests in Atlas will initially consist of a 100% ownership interest in the general partner of Atlas, Atlas Pipeline Partners GP, LLC, which owns:

• a 2.0% general partner interest in Atlas, which entitles it to receive 2.0% of the cash distributed by Atlas;

• all of the incentive distribution rights in Atlas, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed byAtlas as it reaches certain target distribution levels in excess of $0.42 per Atlas unit in any quarter; and

• 1,641,026 common units of Atlas, representing an approximate 12.8% limited partner interest in Atlas.At Atlas’ current quarterly distribution rate of $0.83 per common unit, aggregate quarterly cash distributions to us on all our interests in Atlas would beapproximately $5.0 million. Based on this distribution, we expect that our initial quarterly distribution will be $0.225 per unit, or $0.90 per unit on an annualizedbasis.

Our primary objective is to increase our cash distributions to our unitholders through growth at Atlas. Atlas has grown both through strategic acquisitions andinternal growth projects. Since Atlas’ initial public offering in January 2000, it has completed five acquisitions at an aggregate cost of approximately $516.7million. Atlas’ business strategy is to create capital−efficient growth in distributable cash flow to maximize its distribution to its unitholders by, among otherthings, (1) maximizing cash flows from its existing businesses through marketing of its services and facilities and controlling its operating costs; (2) continuing toincrease the amount of its operating cash flow generated by long−term, fee−based contracts; (3) expanding its existing businesses through internal growthopportunities; (4) expanding its operations through strategic acquisitions; and (5) maintaining a flexible capital structure based on a strong balance sheet byfinancing its growth through a balanced combination of debt and equity.

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We intend to support Atlas in implementing its business strategy by assisting it in identifying, evaluating, and pursuing growth opportunities. In the future, wemay also support the growth of Atlas through the use of our capital resources, which could involve loans or capital contributions to Atlas to provide funding forthe acquisition of a business or asset or for an internal growth project. We may also provide Atlas with other forms of credit support, such as guarantees related tofinancing a project or other types of support related to a merger or acquisition transaction.

Atlas is required by its partnership agreement to distribute all of its cash on hand at the end of each quarter, less reserves established by its general partner in itssole discretion to provide for the proper conduct of Atlas’ business or to provide for future distributions. Since January 1, 2003, Atlas has increased the per unitquarterly cash distribution on its common units by approximately 48%, from the quarterly distribution of $0.56 per unit to $0.83 per unit declared for the fourthquarter of 2005. The following graph shows, for the period from the first quarter of 2003 through the fourth quarter of 2005: (i) Atlas’ quarterly distributions perunit and (ii) total distributions by Atlas to us.

While we, like Atlas, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of Atlas. Most notably,our general partner does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not includeincentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.

Our ownership of Atlas’ incentive distribution rights entitles us to receive an increasing percentage of cash distributed by Atlas as it reaches certain targetdistribution levels. The rights entitle us to receive the following:

• 13.0% of all cash distributed in a quarter after each Atlas unit has received $0.42 for that quarter;

• 23.0% of all cash distributed after each Atlas unit has received $0.52 for that quarter; and

• 48.0% of all cash distributed after each Atlas unit has received $0.60 for that quarter.For the quarter ended December 31, 2005, Atlas declared a distribution of $0.83 per unit, which means we will receive 48.0% of the $0.23 incremental cashdistribution per unit in excess of the

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maximum target distribution level of $0.60 per unit. Because the incentive distribution rights currently participate at the maximum 48.0% target cash distributionlevel, future growth in distributions we receive from Atlas will not result from an increase in the target cash distribution level associated with the incentivedistribution rights.

The graph set forth below demonstrates hypothetical cash distributions payable in respect of our interests in Atlas by showing the total cash allocated to us acrossan illustrative range of annualized cash distributions per unit made by Atlas. The graph illustrates the impact to us of Atlas’ raising or lowering its distributionfrom the most recently declared distribution of $0.83 per common unit ($3.32 on an annualized basis), which will be paid on February 14, 2006. This informationassumes:

• Atlas has 12,549,266 total units outstanding, representing the number of units outstanding at December 31, 2005; and

• through Atlas Pipeline GP, we own (i) 1,641,026 Atlas common units, representing an approximate 12.8% limited partner interest in Atlas, (ii) a 2.0%general partner interest in Atlas and (iii) all the incentive distribution rights in Atlas.

This information is presented for illustrative purposes only and is not intended to be a prediction of future performance and does not attempt to illustrate theimpact of changes in our or Atlas’ business, including changes that may result from changes in natural gas, NGL and condensate prices, changes in economicconditions, the impact of any future acquisitions or expansion projects or the issuance of additional units by Atlas. In addition, the level of cash distributions wereceive may be affected by the various risks associated with an investment in us and the underlying business of Atlas. Please read “Risk Factors.”

We intend to pay to our unitholders, on a quarterly basis, distributions equal to the cash we receive from Atlas, less certain reserves for expenses and other usesof cash, including:

• our general and administrative expenses, including expenses we will incur as the result of being a public company;

• capital contributions to maintain or increase our ownership interest in Atlas; and

• reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions.

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Based on Atlas’ current quarterly distribution, the number of our units outstanding and our expected level of expenses and reserves that our general partnerbelieves prudent to maintain, we expect that our initial quarterly distribution will be $0.225 per common unit, or $0.90 per unit on an annualized basis. Due toour ownership of Atlas’ incentive distribution rights, our cash flows are impacted by changes in Atlas’ distributions to a greater extent than those of Atlas’common unitholders.

If Atlas is successful in implementing its business strategy and increasing distributions to its unitholders, we would generally expect to increase distributions toour unitholders, although the timing and amount of any such increased distributions will not necessarily be comparable to the increased Atlas distributions.However, we cannot assure you that any distributions will be declared or paid. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Executive OfficesOur principal executive offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108, and our phone number is (412) 262−2830. Our website islocated at www.atlaspipelineholdings.com. Information on our website is not incorporated by reference into this prospectus and does not constitute a part of thisprospectus.

Our Limited Partnership Structure and Management

We were formed in December 2005, as a Delaware limited partnership. The chart on the following page depicts our organization and ownership upon completionof this offering, at which time:

• our general partner will own a non−economic general partner interest in us;

• our public unitholders will own 3,600,000 of our common units, representing an approximate 17.1% limited partner interest in us;

• our current owner, Atlas America, will own 17,500,000 of our common units, representing an approximate 82.9% limited partner interest in us; and

• we will continue to own indirectly, through our ownership of Atlas Pipeline Partners GP, LLC, 1,641,026 Atlas common units representing anapproximate 12.8% limited partner interest in Atlas, the 2.0% general partner interest in Atlas and all the incentive distribution rights in Atlas.

Our general partner, Atlas Pipeline Holdings GP, LLC, will manage our operations and activities, including, among other things, establishing the quarterly cashdistribution levels for our common units and reserves it believes prudent to maintain for the proper conduct of our business or to provide for future distributions.Our general partner is entitled to reimbursement for out−of−pocket expenses it incurs on our behalf, but it is not entitled to any other compensation, fees, profitsor other benefits for acting in its capacity as our general partner. All of our executive officers and a majority of the directors of our general partner also serve asexecutive officers and directors of the general partner of Atlas. Atlas America will own all the membership interests in our general partner.

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Atlas Pipeline Holdings, L.P.’s Ownership andOrganizational ChartAfter This Offering

Aggregate ownership of Atlas Pipeline Holdings, L.P. after this offering:Common Units:Public Unitholders 17.1%Atlas America, Inc. 82.9%

Total 100.0%

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The Offering

Common units offered to the public 3,600,000 common units.

4,140,000 common units, if the underwriters exercise their option to purchase additional commonunits in full.

Common units outstanding afterthis offering 21,100,000 common units.

Use of proceeds We expect to receive net proceeds of approximately $79.2 million from the sale of the commonunits, after deducting underwriting discounts and commissions and estimated offering expensespayable by us. Substantially all of the net proceeds from this offering will be distributed to AtlasAmerica.

The net proceeds from any exercise of the underwriters’ option to purchase additional commonunits will be used to fund the redemption of an equal number of common units from AtlasAmerica. Please read “Use of Proceeds.”

Cash distributions We expect to make an initial quarterly distribution of $0.225 per common unit to the extent wehave sufficient cash from operations after establishment of cash reserves and payment of fees andexpenses. Please read “Cash Distribution Policy and Restrictions on Distributions.” We do nothave any subordinated units and our general partner is not entitled to any distributions. Please read“Description of the Common Units” and “The Partnership Agreement of Atlas Pipeline Holdings,L.P.”

We expect to pay you a prorated distribution for the first quarter during which we are a publiclytraded partnership. Assuming that we become a publicly traded partnership before March 31,2006, we will pay you a prorated distribution for the period from the first day our common unitsare publicly traded to and including March 31, 2006. We expect to pay this cash distribution inMay 2006.

The amount of pro forma available cash generated during the twelve months ended December 31,2004 and the twelve months ended September 30, 2005 would have been insufficient byapproximately $21.4 million and $10.0 million, respectively, to pay the full initial distributionamount on all our common units during those periods. Please read “Cash Distribution Policy andRestrictions on Distributions.” We believe that we will have sufficient cash available fordistribution to pay the distributions at the initial distribution rate of $0.225 per unit on all theoutstanding common units for each quarter for the year ending December 31, 2006. See “CashDistribution Policy and Restrictions on Distributions—Assumptions and Considerations” for thespecific assumptions underlying this belief.

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Limited voting rights Our general partner will manage and operate us. Unlike the holders of common stock in acorporation, you will have only limited voting rights on matters affecting our business. You willhave no right to elect our general partner or its directors. Our general partner may not be removedexcept by a vote of the holders of at least 66 2/3% of the outstanding units, including any unitsowned by our affiliates, voting together as a single class. Atlas America will own an aggregate ofapproximately 82.9% of our common units. This will give Atlas America the ability to prevent ourgeneral partner’s involuntary removal. Please read “The Partnership Agreement of Atlas PipelineHoldings, L.P.—Withdrawal or Removal of Our General Partner.”

Limited call right If at any time our affiliates own more than 87.5% of our outstanding common units, our generalpartner has the right, but not the obligation, to purchase all of the remaining common units at aprice not less than the then current market price of the common units. At the completion of thisoffering, Atlas America will own approximately 82.9% of our common units.

Estimated ratio of taxable incometo distributions

We estimate that if you own the common units you purchase in this offering through the recorddate for distributions for the period ending , you will be allocated, on a cumulative basis, anamount of federal taxable income for that period that will be less than % of the cash distributedto you with respect to that cumulative period. For example, if you receive an annual distribution of$0.90 per unit, we estimate that your average allocable federal taxable income per year will be nomore than $ per unit. This estimate is based on assumptions with respect to our operations,gross income, capital expenditures, cash flow and anticipated distributions. Our ratio of taxableincome to cash distributions will be much greater than the ratio applicable to the holders ofcommon units in Atlas because remedial allocations of deductions to us from Atlas will be verylimited and our ownership of incentive distribution rights will cause more taxable income to beallocated to us from Atlas. Further, if Atlas is successful in increasing its distributions over time,our ratio of taxable income to cash distributions will increase. For the basis of this estimate, pleaseread “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of TaxableIncome to Distributions.”

Exchange listing We will apply to list the common units on the New York Stock Exchange under the symbol “ .”

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Atlas Pipeline Partners, L.P.

Atlas is a publicly−traded midstream energy services provider engaged in the transmission, gathering and processing of natural gas. Atlas conducts its businessthrough two operating segments: its Mid−Continent operations and its Appalachian operations.

Through its Mid−Continent operations, Atlas owns and operates:

• a 75% interest in a FERC−regulated, 565−mile interstate pipeline system, which we refer to as Ozark Gas Transmission, that extends from southeasternOklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 322 MMcf/d;

• two natural gas processing plants with aggregate capacity of approximately 230 MMcf/d and one treating facility with a capacity of approximately 200MMcf/d, all located in Oklahoma; and

• 1,765 miles of active natural gas gathering systems located in Oklahoma, Arkansas, northern Texas and the Texas panhandle, which transport gas fromwells and central delivery points in the Mid−Continent region to Atlas’ natural gas processing plants or Ozark Gas Transmission.

Through its Appalachian operations, Atlas owns and operates 1,500 miles of active natural gas gathering systems located in eastern Ohio, western New York andwestern Pennsylvania. Through an omnibus agreement and other agreements between Atlas and Atlas America, the parent of Atlas’ general partner and ourgeneral partner and a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin, Atlas gathers substantially all of the natural gasfor its Appalachian Basin operations from wells operated by Atlas America. Among other things, the omnibus agreement requires Atlas America to connect wellsit operates to Atlas’ gathering systems that are located within 2,500 feet of Atlas’ gathering systems. Atlas is also party to natural gas gathering agreements withAtlas America under which Atlas receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports. Theseagreements are continuing obligations and have no specified term except that they will terminate if Atlas’ general partner is removed without cause.

Since Atlas’ initial public offering in January 2000, Atlas has completed five acquisitions at an aggregate cost of approximately $516.7 million, including, mostrecently, the October 2005 acquisition of Atlas Arkansas Pipeline LLC, which we refer to as Atlas Arkansas and which owns a 75% interest in NOARK PipelineSystem, Limited Partnership, which we refer to as NOARK, and the April 2005 acquisition of ETC Oklahoma Pipeline, Ltd, which we refer to as Elk City.

Both Atlas’ Mid−Continent and Appalachian operations are located in areas of abundant and long−lived natural gas production and significant new drillingactivity. The Ozark Gas Transmission system and Atlas’ gathering systems are connected to approximately 6,250 central delivery points or wells, giving Atlassignificant scale in its service areas. Atlas provides gathering and processing services to the wells connected to its systems, primarily under long−term contracts.Atlas provides fee−based, FERC−regulated transmission services through Ozark Gas Transmission under both long−term and short−term contractualarrangements. Atlas intends to increase the portion of the transmission services provided under long−term contracts. As a result of the location and capacity ofthe Ozark Gas Transmission system and Atlas’ gathering and processing assets, Atlas believes it is strategically positioned to capitalize on the significantincrease in drilling activity in its service areas and the positive price differential across Ozark Gas Transmission, also known as basis spread. Atlas intends tocontinue to expand its business through strategic acquisitions and internal growth projects, including its plan to construct the Sweetwater gas plant, that increasedistributable cash flow per unit.

On October 31, 2005, Atlas acquired from Enogex, Inc., a wholly−owned subsidiary of OGE Energy Corp. (NYSE: OGE), which we refer to as Enogex, all ofthe outstanding equity of Atlas Arkansas for $165.3 million, including estimated related transaction costs, plus $10.2 million for working capital adjustments.Atlas Arkansas owns a 75% interest in NOARK, with the remaining 25%

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interest being owned by Southwestern Energy Pipeline Company, which we refer to as Southwestern, a wholly−owned subsidiary of Southwestern EnergyCompany (NYSE: SWN). The NOARK acquisition further expands Atlas’ activities in the Mid−Continent region and provides an additional source of fee−basedcash flows from a FERC−regulated interstate pipeline system and an intrastate gas gathering system. NOARK’s geographic position relative to Atlas’ otherbusinesses and interconnections with major interstate pipelines also provides it with internal growth opportunities. NOARK’s principal assets include:

• The Ozark Gas Transmission system, a 565−mile FERC−regulated interstate pipeline system which extends from southeast Oklahoma throughArkansas and into southeast Missouri and has a throughput capacity of approximately 322 MMcf/d. The system includes approximately 30 supply anddelivery interconnections and two compressor stations.

• A 365−mile intrastate natural gas gathering system, which we refer to as Ozark Gas Gathering, located in eastern Oklahoma and western Arkansas, and11 associated compressor stations.

Ozark Gas Transmission transports natural gas from receipt points in eastern Oklahoma and western Arkansas to interstate pipelines in northeastern and centralArkansas and to local distribution companies in Arkansas and Missouri. Ozark Gas Gathering gathers natural gas supplies in eastern Oklahoma and westernArkansas which are then transported through Ozark Gas Transmission. Ozark Gas Transmission’s revenue is comprised of FERC−regulated transmission feesthat are based on firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportationrates. The Ozark transmission and gathering systems gathered and transported an average of 163.9 MMcf/d during the nine months ended September 30, 2005,and 207.2 MMcf/d during October 2005.

The NOARK acquisition increases Atlas’ size and presence in the Mid−Continent region, including extending its operations east into the Arkoma Basin wherethe Fayetteville Shale Play is located. The Mid−Continent region, one of the most prolific natural gas−producing regions in North America, has recentlyexperienced a significant increase in oil and gas drilling activity driven by long−term projections of continued growth in U.S. natural gas demand and theapplication of new drilling and production technologies. Atlas believes that the increased drilling activity in the Mid−Continent area, combined with the positivebasis spread across Ozark Gas Transmission, will result in increasing volumes gathered and transported on the Ozark Gas Gathering and Ozark Gas Transmissionsystems.

Atlas recently completed three new gathering and compression projects in Elk City which have increased, and we believe will continue to increase, gatheredvolumes and total gross margin. Atlas also plans to complete construction of a new natural gas processing facility in Oklahoma near its Prentiss treating facilityin the third quarter of 2006, which we refer to as the Sweetwater gas plant. The new plant will be scaled to 120 MMcf/d of processing capacity. Along with theSweetwater gas plant, Atlas will construct a gathering system to be located primarily in western Oklahoma and in the Texas panhandle, more specifically,Beckham and Roger Mills counties in Oklahoma and Hemphill County, Texas. Atlas is currently gathering approximately 30 MMcf/d of natural gas in the ElkCity area for which it earns gathering fees but does not earn processing fees due to the fact that the Elk City plant is currently processing at maximum capacityand is unable to process those volumes. As Atlas completes construction of the Sweetwater gas plant and gathering system, it expects to increase the volumes itgathers in the Elk City area and to process those volumes at the Sweetwater gas plant, thereby enabling it to earn incremental gathering and processing fees. Atlasanticipates that construction of the Sweetwater gas plant and associated gathering system will cost approximately $40.0 million and will generate cash flow of$8.0 million to $10.0 million annually.

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Atlas’ Principal Executive Offices and Internet Address

Atlas’ principal executive offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108, and its phone number is (412) 262−2830. Atlasmaintains a website at www.atlaspipelinepartners.com that provides information about its business and operations. Information contained on this website,however, is not incorporated into or otherwise a part of this prospectus. Atlas also files annual, quarterly and current reports and other information with theSecurities and Exchange Commission, or Commission. Atlas’ Commission filings are available to the public at the Commission’s website at www.sec.gov. Youmay also read and copy any document Atlas files at the Commission’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may obtaininformation on the operation of the Commission’s public reference room by calling the Commission at 1−800−SEC−0330.

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Comparison of Rights of Holders of Our Common Units and Atlas’ Common Units

Our common units and Atlas’ common units are unlikely to trade in simple relation or proportion to one another. Instead, while the trading prices of our commonunits and Atlas’ common units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:

• with respect to its distributions, Atlas’ common unitholders have a priority over our incentive distribution rights in Atlas;

• we participate in Atlas’ general partner’s distributions and the incentive distribution rights, and Atlas’ common unitholders do not; and

• we may in the future enter into other businesses separate from Atlas.The following table compares certain features of Atlas’ common units and our common units.

Atlas’ Common Units Our Common Units

Distributions and Incentive Distribution Rights Atlas has historically madequarterly distributions to itspartners of its cash, less certainreserves for expenses and otheruses of cash, includingreimbursement of expensesowed to its general partner. Fora more detailed discussion,please read “The PartnershipAgreement of Atlas PipelinePartners, L.P.—CashDistribution Policy.” Atlas’general partner owns theincentive distribution rights inAtlas.

We intend to pay ourunitholders quarterlydistributions equal to the cashwe receive from our Atlasdistributions, less certainreserves for expenses and otheruses of cash. Our generalpartner is not entitled to anydistributions. Therefore, ourdistributions are allocatedexclusively to our commonunitholders.

Taxation of Entity and Entity Owners Atlas is a flow−through entitythat is not subject to anentity−level federal income tax.

Similarly, we are aflow−through entity that is notsubject to an entity−levelfederal income tax.

Atlas expects that holders of itscommon units will benefit for aperiod of time from tax basisadjustments and remedialallocations of deductions.

We also expect that holders ofour common units will benefitfor a period of time from taxbasis adjustments and remedialallocations of deductions as aresult of our ownership ofcommon units of Atlas.However, incentive distributionrights do not benefit from suchadjustments and allocations.Therefore, we expect the ratioof our taxable income to thedistributions you will receive tobe higher than the ratio oftaxable income to thedistributions received by thecommon unitholders of Atlas.Moreover, if Atlas is successfulin increasing its distributablecash flow over time, we expectthe ratio of our taxable incometo distributions will increase.

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Atlas’ Common Units Our Common Units

Atlas’ common unitholders willreceive Schedule K−1s fromAtlas reflecting the unitholders’share of Atlas’ items of income,gain, loss and deduction at theend of each fiscal year.

Our common unitholders alsowill receive Schedule K−1sfrom us reflecting theunitholders’ share of our itemsof income, gain, loss anddeduction at the end of eachfiscal year.

Sources of Cash Flow Atlas currently generates itscash flow from its natural gastransmission, gathering andprocessing operations.

Our only cash−generatingassets consist of our interests inAtlas, and we currently have noindependent operations.Accordingly, our financialperformance and our ability topay cash distributions to ourunitholders is currentlycompletely dependent upon theperformance of Atlas.

Limitation on Issuance of Additional Units Atlas may issue an unlimitednumber of additionalpartnership interests and otherequity securities withoutobtaining unitholder approval.

We also may issue an unlimitednumber of additionalpartnership interests and otherequity securities withoutobtaining unitholder approval.

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Summary of Risk Factors

An investment in our common units involves risks associated with us and Atlas as well as tax characteristics associated with interests in publicly tradedpartnerships. You should consider carefully all the risk factors together with all of the other information included in this prospectus before you invest in our units.The risks related to an investment in us, conflicts of interest, Atlas’ business and tax consequences to our unitholders are described under the caption “RiskFactors.” These risks include, but are not limited to, those described below:

Risks Inherent in An Investment in Us

• Our only cash generating assets are our interests in Atlas and our cash flow is therefore completely dependent upon the ability of Atlas to makedistributions to its partners.

• Restrictions in Atlas’ credit facility and our proposed credit facility could limit our ability to make distributions to our unitholders.

• In the future, we may not have sufficient cash to pay distributions at our estimated initial quarterly distribution level or to increase distributions.

• We are largely dependent on Atlas for our growth. As a result of the fiduciary obligations of Atlas’ general partner, which is our wholly ownedsubsidiary, to the unitholders of Atlas, our ability to pursue business opportunities independently will be limited.

• Our ability to sell our partnership interests in Atlas may be limited by securities laws restrictions and liquidity constraints.

• The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, includingsales by our existing unitholders.

• Our unitholders do not elect our general partner or vote on our general partner’s officers or directors, and the rights of our unitholders owning 20% ormore of our units are further restricted under our partnership agreement. Following the completion of this offering, Atlas America will ownapproximately 82.9% of our units, a sufficient number to block any attempt to remove our general partner.

• Atlas may issue additional common units, which may increase the risk of it not having sufficient available cash to maintain or increase its per unitdistribution level.

• You will experience immediate and substantial dilution of $24.63 per common unit in the pro forma net tangible book value of your common units.

Risks Related to Conflicts of Interest

• Although we control Atlas through our ownership of its general partner, Atlas’ general partner owes fiduciary duties to Atlas and Atlas’ unitholders,which may conflict with our interests.

• The fiduciary duties of our general partner’s officers and directors may conflict with those of Atlas’ general partner’s officers and directors.

• Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciaryduties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.

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Risks Related to Atlas’ Business

• Atlas may be unsuccessful in integrating the operations from its recent acquisitions or any future acquisitions with its operations or in realizing all ofthe anticipated benefits of these acquisitions.

• The amount of natural gas Atlas transports, treats or processes will decline over time unless Atlas is able to attract new wells to connect to its gatheringsystems.

• The success of Atlas’ Appalachian operations depends upon Atlas America’s ability to drill and complete commercial producing wells.

• The failure of Atlas America to perform its obligations under Atlas’ natural gas gathering agreements may adversely affect Atlas’ business.

• The success of Atlas’ Mid−Continent operations depends upon its ability to continually find and contract for new sources of natural gas supply fromunrelated third parties.

• Atlas’ Mid−Continent operations currently depend on certain key producers for their supply of natural gas, and the loss of any of these key producerscould reduce Atlas’ revenue.

• The curtailment of operations at, or closure of, either of Atlas’ primary plants could harm its business.

Tax Risks to Our Common Unitholders

• If we or Atlas were treated as a corporation for federal income tax purposes, or if we or Atlas were to become subject to entity−level taxation for statetax purposes, then our cash available for distribution to you would be substantially reduced.

• A successful IRS contest of the federal income tax positions we or Atlas take may adversely affect the market for our common units or Atlas’ units, andthe costs of any contest will reduce cash available for distribution to our unitholders.

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Summary of Conflicts of Interest and Fiduciary Responsibilities

Conflicts of interest exist and may arise in the future as a result of the relationships among us, Atlas and our and their respective general partners and affiliates.Our general partner is controlled by Atlas America. Accordingly, Atlas America has the ability to elect, remove and replace the directors and officers of ourgeneral partner. Similarly, through its indirect control of the general partner of Atlas, Atlas America has the ability to elect, remove and replace the directors andofficers of the general partner of Atlas.

Our general partner and its directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our partners. At the same time,Atlas’ general partner and its directors and officers have fiduciary duties to manage Atlas’ business in a manner beneficial to Atlas and its partners, including us.Certain of the executive officers and non−independent directors of our general partner also serve as executive officers and directors of the general partner ofAtlas. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Atlas, on the one hand, and us, on the otherhand, are in conflict.

The board of directors of Atlas’ general partner or its conflicts committee will resolve any conflict between us and Atlas. The board of directors of our generalpartner or its conflicts committee will resolve any conflict between us and the owners of our general partner and their affiliates. The resolution of these conflictsmay not always be in our best interest or that of our unitholders. For a more detailed description of the conflicts of interest involving us and the resolution ofthese conflicts, please read “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement limits the liability and reduces the fiduciary duties owed by our general partner to our unitholders. Our partnership agreement alsorestricts the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties owed to unitholders.By purchasing our units, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that mightotherwise be considered a breach of fiduciary or other duties under applicable state law. Please read “Conflicts of Interest and Fiduciary Duties—FiduciaryDuties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in ourpartnership agreement and certain legal rights and remedies available to unitholders.

If a business opportunity in respect of any business activity in which Atlas is currently engaged is presented to us, our general partner or Atlas or its generalpartner, then Atlas will have the first right to pursue such opportunity. Pursuant to an omnibus agreement to be entered into in connection with the closing of thisoffering, we will agree to certain business opportunity arrangements to address potential conflicts that may arise between us and Atlas. For more information,please read “Conflicts of Interest and Fiduciary Duties.”

For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

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Summary Historical Consolidated and Pro Forma Financial Data

We were formed in December 2005 and therefore do not have any historical financial statements. Since we will own and control Atlas Pipeline GP, the generalpartner of Atlas, the historical financial statements presented below are of Atlas Pipeline GP, on a consolidated basis, including Atlas.

The historical financial data of Atlas Pipeline GP were derived from audited consolidated financial statements for each of the years ended December 31, 2002,2003 and 2004 and at December 31, 2003 and 2004, which have been audited by Grant Thornton LLP, an independent registered public accounting firm. Thefinancial data for the nine months ended and at September 30, 2004 and 2005 were derived from unaudited consolidated financial statements of Atlas PipelineGP.

We have also included unaudited pro forma financial data that reflects historical results of Atlas Pipeline GP as adjusted on a pro forma basis to give effect toAtlas’ April 2004, July 2004, June 2005 and November 2005 offerings of common units, the issuance of Atlas’ $250 million of 8.125% senior unsecured notes,the completion of the NOARK acquisition and the acquisitions of Spectrum Field Services, Inc., which we refer to as Spectrum, and Elk City, and this offering.

The summary unaudited pro forma balance sheet information reflects the following transactions as if they occurred as of September 30, 2005:

• the NOARK acquisition, which occurred on October 31, 2005, for consideration of $165.3 million, including estimated transaction costs plus $10.2million for working capital adjustments, and the redemption of the portion of the NOARK 7.15% notes severally guaranteed by Atlas Arkansas;

• the amendment of Atlas’ credit facility, which occurred on October 31, 2005, and borrowings under it to finance the NOARK acquisition;

• Atlas’ public offering of 2,700,000 common units, which was completed in November 2005, and 330,000 additional underwriter option units, whichwas completed in December 2005, each at a public offering price of $42.00 per common unit, the net proceeds of which were principally used to repayindebtedness under its credit facility incurred in connection with the NOARK acquisition;

• Atlas’ issuance of $250.0 million of 8.125% senior unsecured notes in a private placement on December 20, 2005, the net proceeds of which wereprincipally used to repay indebtedness under its credit facility; and

• this offering and the application of the net proceeds as described under “Use of Proceeds.”The unaudited pro forma statement of income information for the year ended December 31, 2004 reflects the following transactions as if they occurred as ofJanuary 1, 2004:

• Atlas’ public offering of 750,000 common units, which was completed in April 2004 at a public offering price of $36.00 per common unit, the netproceeds of which were used principally to repay indebtedness under Atlas’ then existing credit facility;

• the Spectrum acquisition, which occurred in July 2004, for total consideration of $141.6 million, including the payment of income taxes due as a resultof the transaction and other related transaction costs;

• Atlas’ public offering of 2,100,000 common units, which was completed in July 2004 at a public offering price of $34.76 per common unit, the netproceeds of which were used principally to repay indebtedness incurred in connection with the Spectrum acquisition;

• the Elk City acquisition, which occurred in April 2005, for total consideration of $196.0 million, including related transaction costs;

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• the closing of Atlas’ $270.0 million credit facility, which occurred in April 2005, and borrowings under it to finance the Elk City acquisition and repayamounts outstanding under Atlas’ previous credit facility;

• Atlas’ public offering of 2,300,000 common units, which was completed in June 2005 at a public offering price of $41.95 per common unit, the netproceeds of which were used principally to repay indebtedness incurred in connection with the Elk City acquisition;

• the NOARK acquisition, which occurred on October 31, 2005, for consideration of $165.3 million, including estimated transaction costs, plus $10.2million for working capital adjustments, and the redemption of the portion of the NOARK 7.15% notes severally guaranteed by Atlas Arkansas;




• this offering and the application of the net proceeds as described under “Use of Proceeds.”

The unaudited pro forma statement of income information for the nine months ended September 30, 2005 reflects the following transactions as if they occurredas of January 1, 2005:



• Atlas’ public offering of 2,300,000 common units, which was completed in June 2005, at a public offering price of $41.95 per common unit, the netproceeds of which were principally used to repay indebtedness incurred in connection with the Elk City acquisition;

• the NOARK acquisition, which occurred on October 31, 2005, for consideration of $165.3 million, including estimated transaction costs plus $10.2million for working capital adjustments, and the redemption of the portion of the NOARK 7.15% notes severally guaranteed by Atlas Arkansas;




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Elk City’s historical fiscal year ended August 31, 2004 is not within 93 days of our fiscal year end. Accordingly, for pro forma purposes, statement of incomeinformation for the year ended December 31, 2004 is based on Elk City’s historical financial results for the twelve months ended November 30, 2004 and wascreated by subtracting the quarter ended November 30, 2003 from Elk City’s income statement for the year ended August 31, 2004 and adding the quarter endedNovember 30, 2004. For our pro forma statement of income information for the nine months ended September 30, 2005, we included Elk City’s incomestatement for the three months ended February 28, 2005. Elk City was included within our historical results for the nine months ended September 30, 2005 fromits date of acquisition on April 14, 2005.

The unaudited pro forma balance sheet and the pro forma statements of income were derived by adjusting the historical financial statements of Atlas Pipeline GP.However, we believe that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited proforma financial data presented are for informational purposes only and are based upon available information and assumptions that we believe are reasonableunder the circumstances. You should not construe the unaudited pro forma financial data as indicative of the combined financial position or results of operationsthat we, Atlas Pipeline GP, Atlas, Spectrum, Elk City and NOARK would have achieved had the transactions been consummated on the dates assumed.Moreover, they do not purport to represent our, Atlas Pipeline GP’s, Atlas’, Spectrum’s, Elk City’s or NOARK’s combined financial position or results ofoperations for any future date or period.

The financial data below should be read together with, and are qualified in their entirety by reference to, Atlas Pipeline GP’s historical consolidated and proforma combined financial statements and the accompanying notes, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,”and the historical consolidated financial statements and the accompanying notes of Spectrum, Elk City and its predecessor and Enogex Arkansas Pipeline, eachof which is set forth elsewhere in this prospectus. The pro forma data are not necessarily reflective of what our results would actually have been had thetransactions actually occurred on the indicated date, nor do they reflect what may actually occur in the future.

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Pro Forma, as adjusted

Years Ended December31,

Nine MonthsEnded

September30,

YearEnded

December31,

NineMonthsEnded

September30,

2002 2003 2004(1) 2004(1) 2005(2) 2004 2005

(unaudited)

(dollars in thousands)

(unaudited)

Statement of income data:Revenue:Natural gas and liquids $ — $ — $ 72,109 $ 30,048 $ 218,268 $ 331,119 $ 301,362Transportation and compression 10,660 15,651 18,800 13,344 16,501 40,283 31,630Interest income and other 7 98 382 282 352 711 496

Total revenue and other income 10,667 15,749 91,291 43,674 235,121 372,113 333,488

Costs and Expenses:Natural gas and liquids — — 58,707 24,588 184,578 286,828 261,794Plant operating — — 2,032 931 7,242 9,105 8,605Transportation and compression 2,062 2,421 2,260 1,709 2,169 6,694 5,716General and administrative 1,482 1,662 4,642 2,901 9,127 10,378 11,544Depreciation and amortization 1,475 1,770 4,471 2,132 8,495 16,803 12,809Loss (gain) on arbitration settlement, net — — (1,457) 2,987 138 (1,457) 138Interest 250 258 2,301 1,202 8,478 26,385 20,059Minority interest in Atlas (3) 2,496 5,066 10,941 3,300 7,240 11,370 5,921Minority interest in NOARK (4) — — — — — 492 440Other — — — — — 555 —

Total costs and expenses 7,765 11,177 83,897 39,750 227,467 367,153 327,026

Net income 2,902 4,572 7,394 3,924 7,654 4,960 6,462Premium on preferred unit redemption — — (400) (400) — (400) —

Net income attributable to owners $ 2,902 $ 4,572 $ 6,994 $ 3,524 $ 7,654 $ 4,560 $ 6,462

Balance sheet data (at period end):Property, plant and equipment, net $ 23,764 $ 29,628 $ 175,259 $ 172,312 $ 304,704 $ 462,626Total assets 38,151 63,170 234,898 236,178 484,458 722,313Total debt, including current portion 6,500 — 54,452 60,220 183,645 289,745Total owners’ equity (deficit) 11,157 15,729 21,405 15,325 (40,880) (40,885)

Other financial data:Gross margin (5) $ 10,660 $ 15,651 $ 32,202 $ 18,804 $ 50,191 $ 84,574 $ 71,198EBITDA (6) 7,123 11,666 25,107 10,558 31,867 59,518 45,251Adjusted EBITDA (6) 7,123 11,666 24,350 13,887 34,814 58,761 48,198

Maintenance capital expenditures $ 170 $ 3,109 $ 1,516 $ 844 $ 1,110Expansion capital expenditures 5,060 4,526 8,527 3,575 33,409

Total capital expenditures $ 5,230 $ 7,635 $ 10,043 $ 4,419 $ 34,519

Operating data:Appalachia:Average throughput volumes (Mcf/d) 50,363 52,472 53,343 52,745 54,804 53,343 54,804Average transportation rate per Mcf $ 0.58 $ 0.82 $ 0.96 $ 0.92 $ 1.10 $ 0.96 $ 1.10Mid−Continent:Velma system:Gathered gas volume (Mcf/d) — — 56,441 55,580 69,091 54,315 69,091Processed gas volume (Mcf/d) — — 55,202 54,755 64,581 52,391 64,581Residue gas volume (Mcf/d) — — 42,659 41,555 52,471 40,702 52,471NGL production (Bbl/d) — — 5,799 5,916 6,812 5,711 6,812Condensate volume (Bbl/d) — — 185 204 269 191 269

Elk City system:Gathered gas volume (Mcf/d) — — — — 242,294 239,804 246,539Processed gas volume (Mcf/d) — — — — 116,688 120,505 116,304Residue gas volume (Mcf/d) — — — — 107,182 110,164 106,391NGL production (Bbl/d) — — — — 5,317 5,331 5,347Condensate volume (Bbl/d) — — — — 121 108 136

NOARK system:Average throughput volume (Mcf/d) — — — — — 155,937 163,906

(1) Includes Atlas’ acquisition of Spectrum on July 16, 2004, representing five and one−half months’ operations for the year ended December 31, 2004 and twoand one−half months’ operations for the nine months ended September 30, 2004.


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(2) Includes Atlas’ acquisition of Elk City on April 14, 2005, representing five and one−half months’ operations for the nine months ended September 30, 2005.

(3) Represents the minority interest in the net income of Atlas.

(4) Represents Southwestern’s 25% minority interest in NOARK, which was acquired on October 31, 2005.

(5) We define gross margin as revenue less purchased product costs. Purchased product costs include the cost of natural gas and NGLs that Atlas purchasesfrom third parties. We view gross margin as an important performance measure of core profitability of our operations and as a key component of our internalfinancial reporting. We believe that investors benefit from having access to the same financial measures that our management uses. The GAAP measuremost directly comparable to gross margin is net income. The following table reconciles our net income to gross margin (in thousands):



Nine MonthsEnded

September30, YearEnded

December31,

NineMonthsEnded

September30,2002 2003 2004 2004 2005 2004 2005

(unaudited) (unaudited)Net income $ 2,902 $ 4,572 $ 7,394 $ 3,924 $ 7,654 $ 4,960 $ 6,462Plus (minus):Interest income and other (7) (98) (382) (282) (352) (711) (496)Plant operating — — 2,032 931 7,242 9,105 8,605Transportation and compression 2,062 2,421 2,260 1,709 2,169 6,694 5,716General and administrative 1,482 1,662 4,642 2,901 9,127 10,378 11,544Depreciation and amortization 1,475 1,770 4,471 2,132 8,495 16,803 12,809Loss (gain) on arbitration settlement, net — — (1,457) 2,987 138 (1,457) 138Interest 250 258 2,301 1,202 8,478 26,385 20,059Minority interest in Atlas 2,496 5,066 10,941 3,300 7,240 11,370 5,921Minority interest in NOARK — — — — — 492 440Other — — — — — 555 —

Gross margin $ 10,660 $ 15,651 $ 32,202 $ 18,804 $ 50,191 $ 84,574 $ 71,198

(6) EBITDA represents net income before net interest expense, income taxes, depreciation and amortization and minority interest in Atlas. Adjusted EBITDA iscalculated by adding to EBITDA other non−cash items such as compensation expenses associated with unit issuances to directors and employees. EBITDAand Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computingEBITDA may not be the same method used to compute similar measures reported by other companies. Adjusted EBITDA includes net gain or loss onarbitration settlement as a non−recurring item. Adjusted EBITDA does not reflect approximately $1.0 million of additional general and administrativeexpenses we expect to incur in connection with our being a public company after this offering.

Certain items excluded from EBITDA are significant components in understanding and assessing an entity’s financial performance, such as their cost ofcapital and its tax structure, as well as historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDAbecause they provide investors and management with additional information as to Atlas’ ability to pay its fixed charges and are presented solely as asupplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cashflow as determined in accordance with generally accepted accounting principles or as indicators of Atlas’ operating performance or liquidity. The tablebelow reconciles Adjusted EBITDA to EBITDA and EBITDA to our net income (in thousands):

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Nine MonthsEnded

September30, YearEnded

December31,

NineMonthsEnded

September30,2002 2003 2004 2004 2005 2004 2005

(unaudited) (unaudited)Net income $ 2,902 $ 4,572 $ 7,394 $ 3,924 $ 7,654 $ 4,960 $ 6,462Plus:Minority interest in Atlas 2,496 5,066 10,941 3,300 7,240 11,370 5,921Interest expense 250 258 2,301 1,202 8,478 26,385 20,059Depreciation and amortization 1,475 1,770 4,471 2,132 8,495 16,803 12,809

EBITDA 7,123 11,666 25,107 10,558 31,867 59,518 45,251Adjustments:Non−cash compensation expense — — 700 342 2,809 700 2,809Loss (gain) on arbitration settlement, net — — (1,457) 2,987 138 (1,457) 138

Adjusted EBITDA $ 7,123 $ 11,666 $ 24,350 $ 13,887 $ 34,814 $ 58,761 $ 48,198

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RISK FACTORS

Partnership interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to thosethat would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors together with all of the otherinformation included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case,we might not be able to pay the quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part ofyour investment.

Risks Inherent in an Investment in Us

Our only cash generating assets are our interests in Atlas, and our cash flow is therefore completely dependent upon the ability of Atlas to makedistributions to its partners.

The amounts of cash that Atlas generates may not be sufficient for it to pay distributions at the current or any other level of distribution. Atlas’ ability to makecash distributions depends primarily on its cash flow. Cash distributions do not depend directly on Atlas’ profitability, which is affected by non−cash items.Therefore, cash distributions may be made during periods when Atlas records losses and may not be made during periods when Atlas records profits. The actualamounts of cash Atlas generates will depend upon numerous factors relating to its business which may be beyond its control, including:

• the demand for and price of its natural gas and NGLs;

• the volume of natural gas Atlas transports;

• continued development of wells for connection to Atlas’ gathering systems;

• the availability of local, intrastate and interstate transportation systems;

• the expenses Atlas incurs in providing its gathering services;

• the cost of acquisitions and capital improvements;

• Atlas’ issuance of equity securities;

• required principal and interest payments on Atlas’ debt;

• prevailing economic conditions;

• fuel conservation measures;

• alternate fuel requirements;

• government regulation and taxation; and

• technical advances in fuel economy and energy generation devices.In addition, the actual amount of cash that Atlas will have available for distribution will depend on other factors, including:

• the level of capital expenditures it makes;

• the sources of cash used to fund its acquisitions;

• its debt service requirements and restrictions on distributions contained in its current or future debt agreements; and

• the amount of cash reserves established by Atlas’ general partner for the conduct of Atlas’ business.Atlas is unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “workingcapital borrowings” under its partnership agreement. Because Atlas will be unable to borrow money to pay distributions unless it establishes a facility that meets

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the definition contained in its partnership agreement, Atlas’ ability to pay a distribution in any quarter is solely dependent on its ability to generate sufficientoperating surplus with respect to that quarter.

Because of these factors, Atlas may not have sufficient available cash each quarter to pay the current declared distribution of $0.83 per quarter or any otheramount. Please read “—Risks Relating to Atlas’ Business” for a discussion of risks affecting Atlas’ ability to generate distributable cash flow.

Restrictions in Atlas’ credit facility and our proposed credit facility could limit our ability to make distributions to our unitholders.

We intend to enter into a credit facility after the closing of this offering. Atlas’ credit facility, and any future credit facility we enter into, will contain covenantslimiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. Atlas’ credit facility alsocontains covenants requiring Atlas to maintain certain financial ratios. In addition, Atlas is prohibited from making any distribution to unitholders if suchdistribution would cause an event of default or otherwise violate a covenant under this credit facility.

Our partnership interests in Atlas are pledged under Atlas America’s credit facility.

Atlas Pipeline GP has granted a security interest and pledged its limited partner and general partner interests in Atlas to Wachovia Bank pursuant to AtlasAmerica’s credit facility. If Atlas America or another party to the credit facility causes an event of default, Wachovia Bank and the other lenders under AtlasAmerica’s credit facility could foreclose on the pledged Atlas partnership interests, which could cause us to lose our ability to manage Atlas and could have amaterial adverse effect on our business, financial condition and results of operations.

If distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial distribution rate, ourunitholders will not be entitled to receive such payments in the future.

Our distributions to our unitholders will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter,including those at the anticipated initial distribution rate, our unitholders will not be entitled to receive such payments in the future. Any distributions received byus from Atlas related to periods prior to the closing of this offering will be distributed entirely to Atlas America. In May 2006, we expect to pay a distribution toour unitholders equal to the initial quarterly distribution prorated for the portion of the quarter ending March 31, 2006 that we are a publicly traded partnership.

We cannot assure you that we will have sufficient available cash to pay our initial quarterly distribution of $0.225 per unit for each quarter followingthe consummation of this offering.

The amount of available cash we need to pay our full initial quarterly distribution on the common units outstanding for the four quarters immediately followingthe completion of this offering is approximately $19.0 million. Our pro forma, as adjusted, available cash deficit generated during fiscal 2004 would have beenapproximately $2.4 million. This amount would have been insufficient by approximately $21.4 million to pay our full initial quarterly distribution amount on allof our outstanding common units. Our pro forma, as adjusted, available cash for the twelve months ended September 30, 2005 would have been approximately$9.0 million. This amount would have been insufficient by approximately $10.0 million to pay our full initial annual distribution amount on all of ouroutstanding units. Please see “Unaudited Pro Forma Available Cash” for a presentation of the amounts of available cash that we would have generated for fiscal2004 and the twelve months ended September 30, 2005.

In the future, we may not have sufficient cash to pay distributions at our estimated initial quarterly distribution level or to increase distributions.

The source of our earnings and cash flow will initially consist exclusively of cash distributions from Atlas. Therefore, the amount of distributions we are able tomake to our unitholders may fluctuate based on the level of distributions Atlas makes to its partners. We cannot assure you that Atlas will continue to makequarterly distributions at its current level or increase its quarterly distributions in the future. In addition, while

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we would expect to increase or decrease distributions to our unitholders if Atlas increases or decreases distributions to us, the timing and amount of suchincreased or decreased distributions, if any, will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made byAtlas to us.

Our ability to distribute cash received from Atlas to our unitholders is limited by a number of factors, including:

• interest expense and principal payments on any current or future indebtedness;

• restrictions on distributions contained in any current or future debt agreements;

• our general and administrative expenses, including expenses we will incur as a result of being a public company;

• expenses of our subsidiaries other than Atlas, including tax liabilities of our corporate subsidiaries, if any;

• reserves necessary for us to make the necessary capital contributions to maintain our 2.0% general partner interest in Atlas as required by its partnershipagreement upon the issuance of additional partnership securities by Atlas; and

• reserves our general partner believes prudent for us to maintain for the proper conduct of our business or to provide for future distributions.We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our estimated initial quarterlydistribution. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond ourcontrol or the control of our general partner. Our estimated cash available to pay distributions for the twelve months ending December 31, 2006 approximatelyequals the amount of cash we need to pay the expected annual distribution of $0.90 per unit. Therefore, a reduction in the amount of cash distributed by Atlas perunit or on the incentive distribution rights, or an increase in our expenses may result in our not being able to pay the expected annual distribution of $0.90 perunit. We do not have any subordinated units, which would have their distributions reduced before distributions to the common units are reduced.

Atlas’ general partner, with our consent, may limit or modify the incentive distributions we are entitled to receive in order to facilitate the growthstrategy of Atlas. Our general partner’s board of directors can give this consent without a vote of our unitholders.

We own Atlas’ general partner, which owns the incentive distribution rights in Atlas that entitle us to receive increasing percentages, up to a maximum of 48.0%,of any cash distributed by Atlas as it reaches certain target distribution levels in excess of $0.42 per unit in any quarter. A substantial portion of the cash flows wereceive from Atlas is provided by these incentive distributions. Atlas’ board of directors may reduce the incentive distribution rights payable to us with ourconsent, which we may provide without the approval of our unitholders.

In order to facilitate acquisitions by Atlas, the general partner of Atlas may elect to limit the incentive distributions we are entitled to receive with respect to aparticular acquisition or unit issuance contemplated by Atlas. This is because a potential acquisition might not be accretive to Atlas’ unitholders as a result of thesignificant portion of that acquisition’s cash flows which would be paid as incentive distributions to us. By limiting the level of incentive distributions inconnection with a particular acquisition or issuance of units of Atlas, the cash flows associated with that acquisition could be accretive to Atlas’ unitholders aswell as substantially beneficial to us. In doing so, the managing board of Atlas’ general partner would be required to consider both its fiduciary obligations toinvestors in Atlas as well as to us. Our partnership agreement specifically permits our general partner to authorize the general partner of Atlas to limit or modifythe incentive distribution rights held by us if our general partner determines that such limitation or modification does not adversely affect our limited partners inany material respect.

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A reduction in Atlas’ distributions will disproportionately affect the amount of cash distributions to which we are currently entitled.

Our ownership of the incentive distribution rights in Atlas, through our ownership of equity interests in Atlas Pipeline GP, the holder of the incentive distributionrights, entitles us to receive our pro rata share of specified percentages of total cash distributions made by Atlas with respect to any particular quarter only in theevent that Atlas distributes more than $0.42 per unit for such quarter. As a result, the holders of Atlas’ common units have a priority over the holders of Atlas’incentive distribution rights to the extent of cash distributions by Atlas up to and including $0.42 per unit for any quarter.

Our incentive distribution rights entitle us to receive increasing percentages, up to 48%, of all cash distributed by Atlas. Because the incentive distribution rightscurrently participate at the maximum 48% target cash distribution level in all distributions made by Atlas above the current distribution level, future growth indistributions we receive from Atlas will not result from an increase in the target cash distribution level associated with the incentive distribution rights.

Furthermore, a decrease in the amount of distributions by Atlas to less than $0.60 per common unit per quarter would reduce Atlas Pipeline GP’s percentage ofthe incremental cash distributions above $0.52 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributionsfrom Atlas would have the effect of disproportionately reducing the amount of all distributions that we receive based on our ownership interest in the incentivedistribution rights in Atlas as compared to cash distributions we receive on our 2.0% general partner interest in Atlas and our Atlas common units.

Our ability to meet our financial needs may be adversely affected by our cash distribution policy and our lack of operational assets.

Our cash distribution policy, which is consistent with our partnership agreement, requires us to distribute all of our available cash quarterly. Our only cashgenerating assets are partnership interests, including incentive distribution rights, in Atlas, and we currently have no independent operations separate from thoseof Atlas. Moreover, a reduction in Atlas’ distributions will disproportionately affect the amount of cash distributions we receive. Given that our cash distributionpolicy is to distribute available cash and not retain it and that our only cash generating assets are partnership interests in Atlas, we may not have enough cash tomeet our needs if any of the following events occur:

• an increase in our operating expenses;

• an increase in general and administrative expenses;

• an increase in principal and interest payments on our outstanding debt;

• an increase in working capital requirements; or

• an increase in cash needs of Atlas or its subsidiaries that reduces Atlas’ distributions.There is no guarantee that our unitholders will receive quarterly distributions from us.

While our cash distribution policy, which is consistent with the terms of our partnership agreement, requires that we distribute all of our available cash quarterly,our cash distribution policy is subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

• We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrativeexpenses, principal and interest payments on debt we may incur, tax expenses, working capital requirements and anticipated cash needs of us or Atlasand its subsidiaries.

• Our cash distribution policy will be, and Atlas’ cash distribution policy is, subject to restrictions on distributions under our anticipated new creditfacility and Atlas’ credit agreements, respectively, such as material financial tests and covenants and limitations on paying distributions during an eventof default.

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• Our general partner’s board of directors will have the authority under our partnership agreement to establish reserves for the prudent conduct of ourbusiness and for future cash distributions to our unitholders, and the managing board of Atlas’ general partner has the authority under Atlas’ partnershipagreement to establish reserves for the prudent conduct of Atlas’ business and for future cash distributions to Atlas’ unitholders. The establishment ofthose reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated cash distribution policy.

• Our partnership agreement, including our cash distribution policy contained therein, may be amended by a vote of the holders of a majority of ourcommon units.

• Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and thedecision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement, and theamount of distributions paid under Atlas’ cash distribution policy and the decision to make any distribution to its unitholders is at the discretion ofAtlas’ general partner, taking into consideration the terms of its partnership agreement.

• Under Section 17−607 of the Delaware Revised Uniform Limited Partnership Act, Atlas may not make a distribution to its partners if the distributionwould cause its liabilities to exceed the fair value of its assets, and we may not make a distribution to you if the distribution would cause our liabilitiesto exceed the fair value of our assets.

Because of these restrictions and limitations on our cash distribution policy and our ability to change our cash distribution policy, we may not have available cashto distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

Our cash distribution policy limits our ability to grow.

Because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. Infact, our growth initially will be completely dependent upon Atlas’ ability to increase its quarterly distribution per unit because currently our onlycash−generating assets are partnership interests in Atlas, including incentive distribution rights. If we issue additional units or incur debt to fund acquisitions andcapital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain orincrease our per unit distribution level.

Consistent with the terms of its partnership agreement, Atlas distributes to its partners its available cash each quarter. In determining the amount of cash availablefor distribution, Atlas sets aside cash reserves, including reserves it believes prudent to maintain for the proper conduct of its business or to provide for futuredistributions. Additionally, it has relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund itsacquisition capital expenditures. Accordingly, to the extent Atlas does not have sufficient cash reserves or is unable to finance growth externally, its cashdistribution policy will significantly impair its ability to grow. In addition, to the extent Atlas issues additional units in connection with any acquisitions or capitalexpenditures, the payment of distributions on those additional units may increase the risk that Atlas will be unable to maintain or increase its per unit distributionlevel, which in turn may impact the available cash that we have to distribute to our unitholders. The incurrence of additional debt to finance its growth strategywould result in increased interest expense to Atlas, which in turn may impact the available cash that we have to distribute to our unitholders.

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The amount of cash distributions from Atlas that we will be able to distribute to you will be reduced by the costs associated with being a publiccompany, other general and administrative expenses, and reserves that our general partner believes prudent to maintain for the proper conduct of ourbusiness and for future distributions.

Before we can pay distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a public company and otheroperating expenses, and we may reserve cash for future distributions during periods of limited cash flows. Prior to this offering, we have been a private companyand have not filed reports with the Commission. Following this offering, we will become subject to the public reporting requirements of the Securities ExchangeAct of 1934, as amended. Although we produce our financial statements in accordance with GAAP, our internal accounting controls may not currently meet allstandards applicable to companies with publicly traded securities. For example, as we become subject to the requirements of Section 404 of Sarbanes−Oxley forthe fiscal year ending December 31, 2007, our auditors may identify weaknesses or deficiencies in the operational effectiveness of our internal controls andprocedures and may advise us that these weaknesses or deficiencies could collectively constitute a significant deficiency that may rise to the level of a materialweakness under Section 404. Similarly, Atlas is subject to Section 404 with the filing of its annual reports on Form 10−K, and its auditors may identifysignificant deficiencies and/or material weaknesses in its internal controls and procedures. In addition, the amount of cash distributions from Atlas that will beavailable for distribution to our unitholders will be reduced by the costs associated with us becoming a public company.

In addition, we may reserve funds to maintain our 2.0% general partner interest in Atlas by making a capital contribution to Atlas when it issues additionalcommon units.

We are largely dependent on Atlas for our growth. As a result of the fiduciary obligations of Atlas’ general partner, which is our wholly ownedsubsidiary, to the unitholders of Atlas, our ability to pursue business opportunities independently will be limited.

We currently intend to grow primarily through the growth of Atlas. While we are not precluded from pursuing business opportunities independently of Atlas, oursubsidiary, as the general partner of Atlas, has fiduciary duties to Atlas unitholders which would make it difficult for us to engage in any business activity that iscompetitive with Atlas. Those fiduciary duties are applicable to us because we control the general partner through our ability to elect all of its directors. Whilethere may be circumstances in which these fiduciary duties may be satisfied while allowing us to pursue business opportunities independent of Atlas, we expectsuch opportunities to be limited. Accordingly, we may be unable to diversify our sources of revenue in order to increase cash distributions to you. See also“—Risks Related to Conflicts of Interest.”

Our ability to sell our partnership interests in Atlas may be limited by securities laws restrictions and liquidity constraints.

All of the 1,641,026 common units of Atlas that we own are unregistered, restricted securities, within the meaning of Rule 144 under the Securities Act of 1933.Unless we exercise our registration rights with respect to these common units, we are limited to selling into the market in any three−month period an amount ofAtlas common units that does not exceed the greater of 1% of the total number of common units outstanding or the average weekly reported trading volume ofthe common units for the four calendar weeks prior to the sale. We face contractual limitations on our ability to sell our general partner interest and incentivedistribution rights and the market for such interests is illiquid.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public markets, includingsales by our existing unitholders.

After this offering, we will have 21,100,000 common units outstanding, which includes the 3,600,000 common units we are selling in this offering that may beresold in the public market immediately. All of our common units that were outstanding prior to our initial public offering will be subject to resale restrictionsunder 180−day lock−up agreements with our underwriters. Each of the lock−up arrangements with the underwriters may be waived in the discretion of LehmanBrothers, Inc. Sales by any of our existing unitholders of a substantial number of our common units in the public markets following this offering, or theperception that such sales might occur, could have a material adverse effect on the price of our common units

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or could impair our ability to obtain capital through an offering of equity securities. In addition, our general partner has agreed to provide registration rights tothese holders, subject to certain limitations. Please read “Units Eligible for Future Sale.”

The control of our general partner may be transferred to a third party, and that party could replace our current management team, in each casewithout unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent ofour unitholders. Furthermore, there is no restriction in our limited partnership agreement on the ability of the owners of our general partner to transfer theirownership interest in our general partner to a third party. The owner of our general partner would then be in a position to replace the board of directors andofficers of our general partner with its own choices and to control the decisions taken by the board of directors and officers.

Atlas’ unitholders have the right to remove Atlas’ general partner with the approval of the holders of 66 2/3% of all units, which would cause us to loseour general partner interest and incentive distribution rights in Atlas and the ability to manage Atlas.

We currently manage Atlas through Atlas Pipeline GP, Atlas’ general partner and our wholly−owned subsidiary. Atlas’ partnership agreement, however, givesunitholders of Atlas the right to remove the general partner of Atlas upon the affirmative vote of holders of 66 2/3% of Atlas’ outstanding units. If Atlas PipelineGP were removed as general partner of Atlas, it would receive cash or common units in exchange for its 2.0% general partner interest and the incentivedistribution rights and would lose its ability to manage Atlas. While the common units or cash we would receive are intended under the terms of Atlas’partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cashover time may not be equivalent to the value of the general partner interest and the incentive distribution rights had we retained them.

If Atlas’ general partner is not fully reimbursed or indemnified for obligations and liabilities it incurs in managing the business and affairs of Atlas, itsvalue, and therefore the value of our common units, could decline.

The general partner of Atlas may make expenditures on behalf of Atlas for which it will seek reimbursement from Atlas. In addition, under Delaware partnershiplaw, the general partner, in its capacity as the general partner of Atlas, has unlimited liability for the obligations of Atlas, such as its debts and environmentalliabilities, except for those contractual obligations of Atlas that are expressly made without recourse to the general partner. To the extent Atlas Pipeline GP incursobligations on behalf of Atlas, it is entitled to be reimbursed or indemnified by Atlas. If Atlas is unable or unwilling to reimburse or indemnify its generalpartner, Atlas Pipeline GP may be unable to satisfy these liabilities or obligations, which would reduce its value and therefore the value of our common units.

The initial public offering price of our common units may not be indicative of the market price of our common units after this offering. In addition, ourunit price may be volatile.

Prior to this offering there has been no public market for our common units. An active market for our common units may not develop or may not be sustainedafter this offering. The initial public offering price of our common units will be determined by negotiations between us and the underwriters based on numerousfactors which we discuss in the “Underwriting” section of this prospectus. This price may not be indicative of the market price for our common units after thisinitial public offering. The market price of our common units could be subject to significant fluctuations after this offering, and may decline below the initialpublic offering price. You may not be able to resell your common units at or above the initial public offering price. The following factors could affect ourcommon unit price:

• Atlas’ operating and financial performance and prospects;

• quarterly variations in the rate of growth of our financial indicators, such as distributable cash flow per common unit, net income and revenue;

• changes in revenue or earnings estimates or publication of research reports by analysts;

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• speculation in the press or investment community;

• sales of our common units by our unitholders;

• announcements by Atlas or its competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capitalcommitments;

• general market conditions; and

• domestic and international economic, legal and regulatory factors unrelated to Atlas’ performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies andpartnerships. These broad market fluctuations may adversely affect the trading price of our common units.

Our common units and Atlas’ common units may not trade in simple relation or proportion to one another. Instead, while the trading prices of our common unitsand Atlas’ common units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:

• Atlas’ cash distributions to its common unitholders have a priority over distributions on its incentive distribution rights;

• we participate in the distributions on our general partner interest in Atlas and the incentive distribution rights in Atlas while Atlas’ common unitholdersdo not; and

• we may enter into other businesses separate and apart from Atlas or any of its affiliates.You may have limited liquidity for your common units. A trading market may not develop for our common units, and you may not be able to resellyour common units at the initial public offering price.

Prior to the offering, there has been no public market for our common units. We do not know the extent to which investor interest will lead to the development ofa trading market or how liquid that market might be. Potential investors may be deterred from investing in our common units for various reasons, including thevery limited number of publicly traded entities whose assets consist exclusively of partnership interests in a publicly traded limited partnership. Also, you maynot be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid−ask spreads,contribute to significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our common units.

Our unitholders do not elect our general partner or vote on our general partner’s officers and directors, and the rights of unitholders owning 20% ormore of our units are further restricted under our partnership agreement. Following the completion of this offering, Atlas America will ownapproximately 82.9% of our units, a sufficient number to block any attempt to remove our general partner.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limitedability to influence management’s decisions regarding our business. Our unitholders did not elect our general partner or the officers or directors of our generalpartner and will have no right to elect our general partner or the officers and directors of our general partner on an annual or other continuing basis in the future.The board of directors of our general partner, including independent directors, is chosen by the members of our general partner.

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Ourgeneral partner may not be removed except upon the vote of the holders of at least 66 2/3% of the outstanding units voting together as a single class. BecauseAtlas America owns approximately 82.9% of our outstanding units, our general partner may not be removed without the consent of Atlas America.

Our unitholders’ voting rights are further restricted by the provision in our limited partnership agreement stating that any units held by a person that owns 20% ormore of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior

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approval of the board of directors of our general partner, cannot be voted on any matter. In addition, our limited partnership agreement contains provisionslimiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ abilityto influence the manner or direction of our management. As a result of these provisions, the price at which our common units will trade may be lower because ofthe absence or reduction of a takeover premium in the trading price.

Atlas may issue additional units, which may increase the risk of it not having sufficient available cash to maintain or increase its per unit distributionlevel.

Atlas has wide discretion to issue additional units, including units that rank senior to its common units and the incentive distributions rights as to quarterly cashdistributions, on the terms and conditions established by its general partner. The payment of distributions on these additional Atlas units may increase the risk ofAtlas being unable to maintain or increase its per unit distribution level. To the extent these new Atlas units are senior to the Atlas common units and theincentive distribution rights, their issuance will increase the uncertainty of the payment of distributions on the common units and the incentive distribution rights.Neither the common units nor the incentive distribution rights are entitled to any arrearages from prior quarters.

We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute your ownership interest in usand may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders on terms and conditions established by ourgeneral partner at any time. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders’ proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• the relative voting strength of each previously outstanding unit may be diminished;

• the ratio of taxable income to distributions may increase; and

• the market price of the common units may decline.Please read “The Partnership Agreement of Atlas Pipeline Holdings, L.P.—Issuance of Additional Securities.”

If in the future we cease to manage and control Atlas through our ownership of its general partner interests, we may be deemed to be an investmentcompany under the Investment Company Act of 1940.

If we cease to manage and control Atlas and are deemed to be an investment company under the Investment Company Act of 1940, we would either have toregister as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure orour contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit ourability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our abilityto borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

You will experience immediate and substantial dilution of $24.63 per common unit in the pro forma net tangible book value of your common units.

The offering price of our common units will be substantially higher than the pro forma net tangible book value per common unit of the outstanding common unitsimmediately after the offering. If you purchase common units in this offering you will incur immediate and substantial dilution in the pro forma net tangible bookvalue per common unit from the price you pay for the common units.

Your liability as a limited partner may not be limited, and our unitholders may have to repay distributions or make additional contributions undercertain circumstances.

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Under Delaware law, you could be held liable for our obligations to the same extent as our general partner if a court determined that the right or the exercise ofthe right by our unitholders as a group to remove or replace our general partner, to approve some amendments to the limited partnership agreement or to takeother action under our limited partnership agreement constituted participation in the “control” of our business.

Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligationsthat are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for theobligations of a limited partnership have not been clearly established in many jurisdictions.

In addition, Section 17−607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to usfor the amount of a distribution for a period of three years from the date of the distribution. Please read “The Partnership Agreement of Atlas Pipeline Holdings,L.P.—Limited Liability” for a discussion of the implications of the limitations on liability to a unitholder.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive ahigher rate of return than would otherwise be obtainable from lower−risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higherrisk−adjusted rates of return by purchasing government−backed debt securities may cause a corresponding decline in demand for riskier investments generally,including yield−based equity investments such as publicly− traded limited partnership interests. Reduced demand for our common units resulting from investorsseeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Risks Related to Conflicts of Interest

Although we control Atlas through our ownership of its general partner, Atlas’ general partner owes fiduciary duties to Atlas and Atlas’ unitholders,which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including Atlas’ general partner, on the onehand, and Atlas and its limited partners, on the other hand. The directors and officers of Atlas Pipeline GP have fiduciary duties to manage Atlas in a mannerbeneficial to us, its owner. At the same time, these directors and officers have a fiduciary duty to manage Atlas in a manner beneficial to Atlas and its limitedpartners. The managing board of Atlas or its conflicts committee will resolve any such conflict and has broad latitude to consider the interests of all parties to theconflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

For example, conflicts of interest may arise in the following situations:

• the allocation of shared overhead expenses to Atlas and us;

• the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Atlas, on the other hand;

• the determination and timing of the amount of cash to be distributed to Atlas’ partners and the amount of cash reserved for the future conduct of Atlas’business;

• the decision as to whether Atlas should make acquisitions, and on what terms; and

• any decision we make in the future to engage in business activities independent of, or in competition with, Atlas.The fiduciary duties of our general partner’s officers and directors may conflict with those of Atlas’ general partner’s officers and directors.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, all of ourgeneral partner’s executive officers and non−independent

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directors also serve as executive officers and directors of Atlas’ general partner, and, as a result, have fiduciary duties to manage the business of Atlas in amanner beneficial to Atlas and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Atlas, onone hand, and us, on the other hand, are in conflict. The resolution of these conflicts of interest may not always be in our best interest or that of our unitholders.For a more detailed description of the conflicts of interest involving our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

If we are presented with certain business opportunities, Atlas will have the first right to pursue such opportunities.

Pursuant to the omnibus agreement to be entered into in connection with the closing of this offering, we will agree to certain business opportunity arrangementsto address potential conflicts that may arise between us and Atlas. If a business opportunity in respect of any business activity in which Atlas is currently engagedis presented to us, our general partner or Atlas or its general partner, then Atlas will have the first right to pursue such business opportunity. The omnibusagreement will provide, among other things, that Atlas will be presumed to desire to acquire the assets until such time as it advises us that it has abandoned suchpursuit, and we may not pursue the opportunity prior to that time. Please read “Conflicts of Interest and Fiduciary Duties.”

Atlas and affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our abilityto acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to ourunitholders.

Neither our partnership agreement nor the omnibus agreement between us, Atlas, Atlas Pipeline GP and Atlas Pipeline Holdings GP, LLC will prohibit Atlas oraffiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us or one another. In addition, Atlas and itsaffiliates or affiliates of our general partner, may acquire, construct or dispose of additional assets related to the transmission, gathering and processing of naturalgas, NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competitionamong these entities could adversely impact Atlas’ or our results of operations and cash available for distribution. Please read “Conflicts of Interest and FiduciaryDuties.”

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciaryduties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.

Following this offering, conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand.As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflictsinclude, among others, the following:

• Our general partner is allowed to take into account the interests of parties other than us, including Atlas and its affiliates and any other businessesacquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

• Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting theremedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duties. As a result of purchasingour units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties underapplicable state law.

• Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities andreserves, each of which can affect the amount of cash that is available for distribution to our unitholders.

• Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering intoadditional contractual arrangements with any

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of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

• Our general partner controls the enforcement of obligations owed to us by it and its affiliates.

• Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest and Fiduciary Duties.”

Our general partner may not be fully reimbursed for the use of its officers and employees by Atlas’ general partner.

Our general partner shares officers and administrative personnel with Atlas’ general partner to operate both our business and Atlas’ business. In that case, ourgeneral partner’s officers, who are also the officers of Atlas’ general partner, will allocate, in their reasonable and sole discretion, the time its employees spend onour behalf and on behalf of Atlas. These allocations may not necessarily be the result of arms−length negotiations between Atlas’ general partner and our generalpartner. Although our general partner intends to be reimbursed by Atlas’ general partner for its employees’ activities, due to the nature of the allocations, thisreimbursement may not exactly match the actual time and overhead spent.

Our partnership agreement limits our general partner’s fiduciary duties to us and our unitholders and restricts the remedies available to ourunitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. Forexample, our partnership agreement:

• permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitlesour general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of,or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to theunits it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment toour partnership agreement;

• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as itacted in good faith, meaning it believed the decisions were in the best interests of our partnership;

• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the audit and conflicts committee of the board ofdirectors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided toor available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair andreasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may beparticularly advantageous or beneficial to us;

• provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner acted in good faith, and in anyproceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcomingsuch presumption; and

• provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for anyacts or omissions unless there has been a final and non−appealable judgment entered by a court of competent jurisdiction determining that the generalpartner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledgethat such person’s conduct was criminal.

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In order to become a limited partner of our partnership, our unitholders are required to agree to be bound by the provisions in the partnership agreement,including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 87.5% of our outstanding units, our general partner will have the right, but not the obligation,which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than theirthen−current market price. As a result, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment.You may also incur a tax liability upon a sale of your units. At the completion of this offering, Atlas America will own approximately 82.9% of our units. Pleaseread “The Partnership Agreement of Atlas Pipeline Holdings, L.P.—Limited Call Right.”

Risks Relating to Atlas’ Business

Because our cash flow will initially consist exclusively of distributions from Atlas, risks to Atlas’ business are also risks to us. We have set forth below thematerial risks to Atlas’ business or results of operations, the occurrence of which could negatively impact Atlas’ financial performance and decrease the amountof cash it is able to distribute to us, thereby decreasing the amount of cash we have available for distribution to our unitholders.

Atlas may be unsuccessful in integrating the operations from its recent acquisitions or any future acquisitions with its operations and in realizing all ofthe anticipated benefits of these acquisitions.

Atlas acquired Elk City in April 2005 and completed the NOARK acquisition in October 2005 and is currently in the process of integrating their operations withits operations. Atlas also has an active, on−going program to identify other potential acquisitions. The integration of previously independent operations withAtlas can be a complex, costly and time−consuming process. The difficulties of combining Elk City and NOARK, as well as any operations Atlas may acquire inthe future, with its existing operations include, among other things:

• operating a significantly larger combined entity;

• the necessity of coordinating geographically disparate organizations, systems and facilities;

• integrating personnel with diverse business backgrounds and organizational cultures;

• consolidating operational and administrative functions;

• integrating internal controls, compliance under Sarbanes−Oxley Act of 2002 and other corporate governance matters;

• the diversion of management’s attention from other business concerns;

• customer or key employee loss from the acquired businesses;

• a significant increase in Atlas’ indebtedness; and

• potential environmental or regulatory liabilities and title problems.The process of combining companies or the failure to integrate them successfully could harm Atlas’ business or future prospects, and result in significantdecreases in Atlas’ gross margin and cash flows.

The acquisitions of the Elk City and NOARK operations have substantially changed Atlas’ business, making it difficult to evaluate Atlas’ businessbased upon its historical financial information.

The acquisitions of the Elk City and NOARK operations have significantly increased Atlas’ size and substantially redefined its business plan, expanded Atlas’geographic market and resulted in large changes to its revenue and expenses. As a result of these acquisitions, and Atlas’ continued plan to acquire and integrateadditional companies that it believes present attractive opportunities, Atlas’ financial results for any period or changes in its results across periods may continueto dramatically change. Atlas’ historical financial results,

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therefore, should not be relied upon to accurately predict its future operating results, thereby making the evaluation of its business more difficult.

Due to its lack of asset diversification, negative developments in Atlas’ operations would reduce its ability to make distributions to its unitholders.

Atlas relies exclusively on the revenue generated from its transportation, gathering and processing operations, and as a result, its financial condition dependsupon prices of, and continued demand for, natural gas and NGLs. Due to Atlas’ lack of asset−type diversification, a negative development in one of thesebusinesses would have a significantly greater impact on Atlas’ financial condition and results of operations than if it maintained more diverse assets.

Atlas’ construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks,which could impair its results of operations and financial condition.

One of the ways Atlas may grow its business is through the construction of new assets, such as the Sweetwater gas plant. The construction of additions ormodifications to Atlas’ existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legaluncertainties beyond Atlas’ control and require the expenditure of significant amounts of capital. Any projects Atlas undertakes may not be completed onschedule at the budgeted cost, or at all. Moreover, its revenue may not increase immediately upon the expenditure of funds on a particular project. For instance, ifAtlas expands a gathering system, the construction may occur over an extended period of time, and it will not receive any material increases in revenue until theproject is completed. Moreover, Atlas may construct facilities to capture anticipated future growth in production in a region in which growth does notmaterialize. Since Atlas is not engaged in the exploration for and development of natural gas reserves, it often does not have access to estimates of potentialreserves in an area before constructing facilities in the area. To the extent Atlas relies on estimates of future production in Atlas’ decision to construct additions toits systems, the estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result,new facilities may not be able to attract enough throughput to achieve Atlas’ expected investment return, which could impair Atlas’ results of operations andfinancial condition. In addition, Atlas’ actual revenue from a project could materially differ from expectations as a result of the price of natural gas, the NGLcontent of the natural gas processed and other economic factors described in this section.

In particular, if the Sweetwater gas plant does not generate the incremental cash flow we expect, or if the generation of such cash flow is materially delayed, wemay not have sufficient available cash to pay distributions at the initial distribution rate. In addition to the risks discussed above, expected revenue from theSweetwater gas plant could be reduced or delayed due to the following reasons:

• difficulties in obtaining equity or debt financing for construction and operating costs;

• difficulties in obtaining permits or other regulatory or third party consents;

• construction and operating costs exceeding budget estimates;

• revenue being less than expected due to lower commodity prices or lower demand;

• difficulties in obtaining consistent supplies of natural gas; and

• terms in operating agreements that are not favorable to us.If Atlas is unable to obtain new rights−of−way or the cost of renewing existing rights−of−way increases, then it may be unable to fully execute its growthstrategy and its cash flows could be reduced.

The construction of additions to Atlas’ existing gathering assets may require it to obtain new rights−of−way before constructing new pipelines. Atlas may beunable to obtain rights−of−way to connect new natural gas supplies to its existing gathering lines or capitalize on other attractive expansion opportunities.Additionally, it may become more expensive for Atlas to obtain new rights−of−way or to renew existing rights−of−way. If the cost of obtaining newrights−of−way or renewing existing rights−of−way increases, then Atlas’ cash flows could be reduced.

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Atlas’ profitability is affected by the volatility of prices for natural gas and NGL products.

Atlas derives a majority of its gross margin from percentage of proceeds contracts. As a result, Atlas’ income depends to a significant extent upon the prices atwhich the natural gas it transports and the NGLs it produces are sold. Additionally, changes in natural gas prices may indirectly impact Atlas’ profitability sinceprices can influence drilling activity and well operations and thus the volume of natural gas Atlas gathers and processes. Historically, the price of both natural gasand NGLs has been subject to significant volatility in response to relatively minor changes in the supply and demand for natural gas and NGL products, marketuncertainty and a variety of additional factors beyond Atlas’ control, including those described in “Our only cash generating assets are our partnership interests inAtlas, and our cash flow is therefore completely dependent upon the ability of Atlas to make distributions to its partners,” above. Atlas expects this volatility tocontinue. This volatility may cause Atlas’ gross margin and cash flows to vary widely from period to period. Atlas’ hedging strategies may not be sufficient tooffset price volatility risk and, in any event, do not cover all of the throughput volumes subject to percentage of proceeds contracts. Moreover, hedges are subjectto inherent risks, described in “—Atlas’ hedging strategies may fail to protect it and could reduce its gross margin and cash flow.”

The amount of natural gas Atlas transports, treats or processes will decline over time unless it is able to attract new wells to connect to its gatheringsystems.

Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned.Failure to connect new wells to Atlas’ gathering systems could, therefore, result in a substantial reduction of the amount of natural gas transported over time andcould, upon exhaustion of the current wells, cause Atlas to abandon one or more of its gathering systems and, possibly, cease operations. The primary factorsaffecting Atlas’ ability to connect new supplies of natural gas to its gathering systems include its success in contracting for existing wells that are not committedto other systems, the level of drilling activity near its gathering systems and, in the Mid−Continent region, its ability to attract natural gas producers away fromits competitors’ gathering systems. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of newoil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. Atlas has no control over the level of drilling activity inits service areas, the amount of reserves underlying wells that connect to its systems and the rate at which production from a well will decline. In addition, Atlashas no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand forhydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital. Because Atlas’ operating costs arefixed to a significant degree, a reduction in the natural gas volumes it transports, treats or processes would result in a reduction in Atlas’ gross margin and cashflows.

The success of Atlas’ Appalachian operations depends upon Atlas America’s ability to drill and complete commercial producing wells.

Substantially all of the wells Atlas connects to its gathering systems in its Appalachian service area are drilled and operated by Atlas America for drillinginvestment partnerships sponsored by Atlas America. As a result, Atlas’ Appalachian operations depend principally upon the success of Atlas America insponsoring drilling investment partnerships and completing wells for these partnerships. Atlas America operates in a highly competitive environment foracquiring undeveloped leasehold acreage and attracting capital. Atlas America may not be able to compete successfully in the future in acquiring undevelopedleasehold acreage or in raising additional capital through its drilling investment partnerships. Furthermore, Atlas America is not required to connect wells forwhich it is not the operator to Atlas’ gathering systems. If Atlas America cannot or does not continue to sponsor drilling investment partnerships, if the amount ofmoney raised by those partnerships decreases, or if the number of wells actually drilled and completed as commercially producing wells decreases, the amount ofnatural gas transported by Atlas’ Appalachian gathering systems would substantially decrease and could, upon exhaustion of the wells currently connected to itsgathering systems, cause it to abandon one or more of its Appalachian gathering systems, thereby materially reducing its gross margin and cash flows.

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The failure of Atlas America to perform its obligations under Atlas’ natural gas gathering agreements may adversely affect Atlas’ business.

Substantially all of Atlas’ Appalachian operating system revenue currently consists of the fees Atlas receives under the master natural gas gathering agreementand other transportation agreements it has with Atlas America. Atlas expects to derive a material portion of its gross margin from the services it provides underits contracts with Atlas America for the foreseeable future. Any factor or event adversely affecting Atlas America’s business or its ability to perform under itscontracts with Atlas or any default or nonperformance by Atlas America of its contractual obligations to Atlas, could reduce Atlas’ gross margin and cash flows.

The success of Atlas’ Mid−Continent operations depends upon its ability to continually find and contract for new sources of natural gas supply fromunrelated third parties.

Unlike its Appalachian operations, none of the drillers or operators in Atlas’ Mid−Continent service area is an affiliate of Atlas. Moreover, Atlas’ agreementswith most of the drillers and operators with which its Mid−Continent operations do business do not require them to dedicate significant amounts of undevelopedacreage to Atlas’ systems. As a result, Atlas does not have assured sources to provide it with new wells to connect to its Mid−Continent gathering systems.Failure to connect new wells to its Mid−Continent operations will, as described in “—The amount of natural gas Atlas transports, treats or processes will declineover time unless it is able to attract new wells to connect to its gathering systems,” above, reduce its gross margin and cash flows.

Atlas’ Mid−Continent operations currently depend on certain key producers for their supply of natural gas, and the loss of any of these key producerscould reduce Atlas’ revenue.

During 2004, Chesapeake, Kaiser−Francis Oil Company, Burlington Resources Inc., St. Mary Land and Exploration Company and Samson Resources Co.supplied Atlas’ Mid−Continent system with a majority of its natural gas supply. If these producers reduce the volumes of natural gas that they supply to Atlas,Atlas’ gross margin and cash flows would be reduced unless it obtains comparable supplies of natural gas from other producers.

The curtailment of operations at, or closure of, either of Atlas’ processing plants could harm its business.

Atlas has one processing plant for its Elk City operation and one active processing plant for its Velma operation. If operations at either plant were to be curtailed,or closed, whether due to accident, natural catastrophe, environmental regulation or for any other reason, Atlas’ ability to process natural gas from the relevantgathering system and, as a result, its ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a shortperiod, Atlas’ gross margin and cash flows would be materially reduced.

Atlas may face increased competition in the future in its Mid−Continent service areas.

Atlas’ Mid−Continent operations may face competition for well connections. Duke Energy Field Services, LLC, ONEOK, Inc., Carrera Gas Company,Cimmarron Transportation, LLC and Enogex, Inc. operate competing gathering systems and processing plants in Atlas’ Velma service area. In Atlas’ Elk Cityservice area, ONEOK, Enbridge Energy Partners, L.P., CenterPoint Energy, Inc. and Enogex operate competing gathering systems and processing plants.Centerpoint Energy, Inc.’s interstate system is the nearest direct competitor to Atlas’ Ozark Gas Transmission system. Centerpoint and Enogex Inc. operatecompeting gathering systems in Ozark Gas Gathering’s service area. Some of Atlas’ competitors have greater financial and other resources than Atlas does. Ifthese companies become more active in its Mid−Continent service areas, Atlas may not be able to compete successfully with them in securing new wellconnections or retaining current well connections. If Atlas does not compete successfully, the amount of natural gas it transports, processes and treats willdecrease, reducing its gross margin and cash flows.

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The amount of natural gas Atlas transports, treats or processes may be reduced if the public utility and interstate pipelines to which it delivers gascannot or will not accept the gas.

Atlas’ gathering systems principally serve as intermediate transportation facilities between sales lines from wells connected to its systems and the public utility orinterstate pipelines to which it delivers natural gas. If one or more of these pipelines has service interruptions, capacity limitations or otherwise does not acceptthe natural gas Atlas transports, and Atlas cannot arrange for delivery to other pipelines, local distribution companies or end users, the amount of natural gas ittransports may be reduced. Since Atlas’ revenue depends upon the volumes of natural gas it transports, this could result in a material reduction in its gross marginand cash flows.

Before acquiring its Velma and Elk City operations, Atlas had no previous experience either in its Mid−Continent service area or in operating naturalgas processing plants.

Atlas’ Mid−Continent gathering systems are located in Oklahoma and northern Texas, areas in which it has been involved only since July 2004 as a result of theVelma acquisition and, in April 2005, the Elk City acquisition. In addition, as a result of these acquisitions, Atlas began to operate natural gas processing plants,a business in which it had no prior operating experience. Atlas depends upon the experience, knowledge and business relationships that have been developed bythe senior management of its Mid−Continent operations to operate successfully in the region. The loss of the services of one or more members of Atlas’Mid−Continent senior management, in particular, Robert R. Firth, President, and David D. Hall, Chief Financial Officer, could limit its growth or ability tomaintain its current level of operations in the Mid−Continent region.

Atlas may not be able to execute its growth strategy successfully.

Atlas’ strategy contemplates substantial growth through both the acquisition of other gathering systems and processing assets and the expansion of its existinggathering systems and processing assets. Atlas’ growth strategy involves numerous risks, including:

• it may not be able to identify suitable acquisition candidates;

• it may not be able to make acquisitions on economically acceptable terms;

• its costs in seeking to make acquisitions may be material, even if it cannot complete any acquisition it has pursued;

• irrespective of estimates at the time it makes an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus;

• it may encounter difficulties in integrating operations and systems; and

• any additional debt it incurs to finance an acquisition may impair Atlas’ ability to service its existing debt.Limitations on Atlas’ access to capital or the market for its common units will impair its ability to execute its growth strategy.

Atlas’ ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, Atlas has financed itsacquisitions, and to a much lesser extent, expansions of its gathering systems, by bank credit facilities and the proceeds of public equity offerings of its commonunits. If Atlas is unable to access the capital markets, it may be unable to execute its strategy of growth through acquisitions.

Atlas’ hedging strategies may fail to protect it and could reduce its gross margin and cash flow.

Atlas pursues various hedging strategies to seek to reduce its exposure to losses from adverse changes in the prices for natural gas and NGLs. Atlas’ hedgingactivities will vary in scope based upon the level and volatility of natural gas and NGL prices and other changing market conditions. Atlas’ hedging activity mayfail to protect or could harm it because, among other things:

• hedging can be expensive, particularly during periods of volatile prices;

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• available hedges may not correspond directly with the risks against which it seeks protection;

• the duration of the hedge may not match the duration of the risk against which it seeks protection; and

• the party owing money in the hedging transaction may default on its obligation to pay.

Atlas’ midstream natural gas operations may incur significant costs and liabilities resulting from a failure to comply with new or existingenvironmental regulations or a release of hazardous substances into the environment.

The operations of Atlas’ gathering systems, plant and other facilities are subject to stringent and complex federal, state and local environmental laws andregulations. These laws and regulations can restrict or impact Atlas’ business activities in many ways, including restricting the manner in which it disposes ofsubstances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure tocomply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetarypenalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint andseveral liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is notuncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release ofsubstances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in Atlas’ business due to its handling of natural gas and other petroleum products,air emissions related to its operations, historical industry operations including releases of substances into the environment, and waste disposal practices. Forexample, an accidental release from one of Atlas’ pipelines or processing facilities could subject it to substantial liabilities arising from environmental cleanup,restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage, andfines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcementpolicies could significantly increase Atlas’ compliance costs and the cost of any remediation that may become necessary. Atlas may not be able to recover someor any of these costs from insurance.

Atlas is subject to operating and litigation risks that may not be covered by insurance.

Atlas’ operations are subject to all operating hazards and risks incidental to transporting and processing natural gas and NGLs. These hazards include:

• damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;

• inadvertent damage from construction and farm equipment;

• leakage of natural gas, NGLs and other hydrocarbons;

• fires and explosions;

• other hazards, including those associated with high−sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution andsuspension of operations; and

• acts of terrorism directed at Atlas’ pipeline infrastructure, production facilities, transmission and distribution facilities and surrounding properties.As a result, Atlas may be a defendant in various legal proceedings and litigation arising from its operations. Atlas may not be able to maintain or obtain insuranceof the type and amount it desires at reasonable rates. As a result of market conditions, premiums and deductibles for some of Atlas’ insurance policies haveincreased substantially, and could escalate further. In some instances, insurance could become unavailable or available only for reduced amounts of coverage. Forexample, insurance carriers are now requiring broad exclusions for losses due to war risk and terrorist acts. If Atlas were to incur a significant liability for whichit was not fully insured, its gross margin and cash flows would be materially reduced.

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Regulation of Atlas’ gathering operations could increase its operating costs, decrease its revenue, or both.

Currently Atlas’ gathering of natural gas from wells is exempt from regulation under the Natural Gas Act of 1938. However, the implementation of new laws orpolicies, or interpretations of existing laws, could subject Atlas to regulation by FERC under the Natural Gas Act. Atlas expects that any such regulation wouldincrease its costs, decrease its gross margin and cash flows, or both.

FERC regulation will still affect Atlas’ business and the market for its products. FERC’s policies and practices affect a range of Atlas’ natural gas pipelineactivities, including, for example, its policies on open access transportation, ratemaking, capacity release, and market center promotion, which indirectly affectintrastate markets. In recent years, FERC has pursued pro−competitive policies in its regulation of interstate natural gas pipelines. However, Atlas cannot assureyou that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gastransportation capacity.

Other state and local regulations will also affect Atlas’ business. Matters subject to regulation include rates, service and safety. Atlas’ gathering lines are subjectto ratable take and common purchaser statutes in Texas and Oklahoma. Ratable take statutes generally require gatherers to take, without undue discrimination,natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase withoutundue discrimination as to source of supply or producer. These statutes restrict Atlas’ right as an owner of gathering facilities to decide with whom it contracts topurchase or transport natural gas.

Federal law leaves any economic regulation of natural gas gathering to the states. Texas and Oklahoma have adopted complaint−based regulation of natural gasgathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to naturalgas gathering access and, in Texas and Oklahoma, with respect to rate discrimination. Should a complaint be filed or regulation by the Texas RailroadCommission or Oklahoma Corporation Commission become more active, Atlas’ revenue could decrease.

Increased regulatory requirements relating to the integrity of the Ozark Gas Transmission pipeline will require it to spend additional money to comply with theserequirements. Ozark Gas Transmission is subject to extensive laws and regulations related to pipeline integrity. For example, federal legislation signed into lawin December 2002 includes guidelines for the U.S. Department of Transportation and pipeline companies in the areas of testing, education, training andcommunication. Compliance with existing and recently enacted regulations requires significant expenditures. Additional laws and regulations that may beenacted in the future, such as U.S. Department of Transportation implementation of additional hydrostatic testing requirements, could significantly increase theamount of these expenditures.

Ozark Gas Transmission is subject to FERC rate−making policies that could have an adverse impact on Atlas’ ability to establish rates that wouldallow it to recover the full cost of operating the pipeline.

Rate−making policies by FERC could affect Ozark Gas Transmission’s ability to establish rates, or to charge rates that would cover future increases in its costs,or even to continue to collect rates that cover current costs. Natural gas companies may not charge rates that have been determined not to be just and reasonableby FERC. The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC−approved tariffs. Pursuantto FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Atlas cannot assureyou that FERC will continue to pursue its approach of pro−competitive policies as it considers matters such as pipeline rates and rules and policies that mayaffect rights of access to natural gas capacity and transportation facilities. Any successful complaint or protest against Ozark Gas Transmission’s rates couldreduce Atlas’ revenue associated with providing transmission services. Atlas cannot assure you that it will be able to recover all of Ozark Gas Transmission’scosts through existing or future rates.

Ozark Gas Transmission is subject to regulation by FERC in addition to FERC rules and regulations related to the rates it can charge for its services.

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FERC’s regulatory authority also extends to:

• operating terms and conditions of service;

• the types of services Ozark Gas Transmission may offer to its customers;

• construction of new facilities;

• acquisition, extension or abandonment of services or facilities;

• accounts and records; and

• relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.FERC action in any of these areas or modifications of its current regulations can impair Ozark Gas Transmission’s ability to compete for business, the costs itincurs in its operations, the construction of new facilities or its ability to recover the full cost of operating its pipeline. For example, the development of uniforminterstate gas quality standards by FERC could create two distinct markets for natural gas—an interstate market subject to uniform minimum quality standardsand an intrastate market with no uniform minimum quality standards. Such a bifurcation of markets could make it difficult for Atlas’ pipelines to compete in bothmarkets or to attract certain gas supplies away from the intrastate market. The time FERC takes to approve the construction of new facilities could raise the costsof Atlas’ projects to the point where they are no longer economic.

FERC has authority to review pipeline contracts. If FERC determines that a term of any such contract deviates in a material manner from a pipeline’s tariff,FERC typically will order the pipeline to remove the term from the contract and execute and refile a new contract with FERC or, alternatively, to amend its tariffto include the deviating term, thereby offering it to all shippers. If FERC audits a pipeline’s contracts and finds deviations that appear to be undulydiscriminatory, FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should Ozark Gas Transmission fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantialpenalties and fines. Under the recently enacted Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties forcurrent violations of up to $1,000,000 per day for each violation.

Finally, Atlas cannot give any assurance regarding the likely future regulations under which it will operate Ozark Gas Transmission or the effect such regulationcould have on its business, financial condition, results of operations and ability to make distributions to its unitholders.

Compliance with pipeline integrity regulations issued by the United States Department of Transportation and state agencies could result in substantialexpenditures for testing, repairs and replacement.

United States Department of Transportation and state agency regulations require pipeline operators to develop integrity management programs for transportationpipelines located in “high consequence areas.” The regulations require operators to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventative and mitigating actions.Atlas does not believe that the cost of implementing integrity management program testing along certain segments of its pipeline will have a material effect on itsresults of operations. This does not include the

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costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costscould be substantial.

Tax Risks to Common Unitholders

For a discussion of the expected material federal income tax consequences of owning and disposing of common units, see “Material Tax Consequences.”

If we or Atlas were treated as a corporation for federal income tax purposes, or if we or Atlas were to become subject to entity−level taxation for statetax purposes, then our cash available for distribution to you would be substantially reduced.

The value of our investment in Atlas depends largely on it being treated as a partnership for federal income tax purposes, which requires that 90% or more ofAtlas’ gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Atlas may not meet thisrequirement or current law may change so as to cause, in either event, Atlas to be treated as a corporation for federal income tax purposes or otherwise subject tofederal income tax. Moreover, the anticipated after−tax benefit of an investment in our common units depends largely on our being treated as a partnership forfederal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If Atlas were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate, which iscurrently a maximum of 35%. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or creditswould flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of ourunits.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate.Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you.Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Thus, treatment of us as acorporation would result in a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

Current law may change, causing us or Atlas to be treated as a corporation for federal income tax purposes or otherwise subjecting us or Atlas to entity leveltaxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through theimposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or Atlas as an entity, the cash available for distributionto you would be reduced.

A successful IRS contest of the federal income tax positions we, or Atlas, take may adversely affect the market for our common units or Atlas units, andthe costs of any contest will reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter that affects us.Moreover, Atlas has not requested any ruling from the IRS with respect to its treatment as a partnership for federal income tax purposes or any other matter thataffects it. The IRS may adopt positions that differ from the positions we or Atlas take. It may be necessary to resort to administrative or court proceedings tosustain some or all of the positions we or Atlas take. A court may disagree with some or all of the positions we or Atlas take. Any contest with the IRS maymaterially and adversely impact the market for our common units or Atlas’ units and the price at which they trade. In addition, the cost of any contest betweenAtlas and the IRS will result in a reduction in cash available for distribution to Atlas unitholders and thus indirectly by us, as a unitholder and as the owner of thegeneral partner of Atlas. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholdersand thus will be borne indirectly by our unitholders.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

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You will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not youreceive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability thatresults from the taxation of your share of our taxable income.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in Atlas.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in Atlas. Other holders of commonunits in Atlas will receive remedial allocations of deductions from Atlas. Although we will receive remedial allocations of deductions from Atlas, remedialallocations of deductions to us will be very limited. In addition, our ownership of Atlas incentive distribution rights will cause more taxable income to beallocated to us from Atlas than will be allocated to holders who hold only common units in Atlas. If Atlas is successful in increasing its distributions over time,our income allocations from our Atlas incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will increase.Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in Atlas, your allocable taxableincome will be significantly greater than that of a holder of common units in Atlas who receives cash distributions from Atlas equal to the cash distributions youreceive from us.

Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those commonunits. Prior distributions to you in excess of the total net taxable income allocated to you, which decreased the tax basis in your common units, will, in effect,become taxable income to you if the common units are sold at a price greater than your tax basis in those common units, even if the price is less than the originalcost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.

Tax−exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax−exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non−U.S.persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individualretirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non−U.S.persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non−U.S. persons will be required to file United Statesfederal income tax returns and pay tax on their share of our taxable income.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challengethis treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with allaspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to ourunitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the valueof our common units or result in audits of and adjustments to our unitholders’ tax returns.

The sale or exchange of 50% or more of our or Atlas’ capital and profits interests within a 12−month period will result in the termination of our orAtlas’ partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests inour capital and profits within a 12−month period. Likewise, Atlas will be considered to have terminated its partnership for federal income tax purposes if there isa sale or exchange of 50% or more of the total interests in Atlas’ capital and profits within a 12−month period. The termination would, among other things, resultin the closing of our or Atlas’ taxable year for all

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unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs.Thus, if this occurs, you will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentageof the cash distributed to you with respect to that period. Please read “Material Tax Consequences—Disposition of Common Units—Constructive Termination”for a discussion of the consequences of our termination for federal income tax purposes.

Unitholders may be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxesand estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or Atlas do business or own property now or in the future,even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay stateand local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. Weand Atlas presently anticipate that substantially all of our income will be generated in the following states: Arkansas, Missouri, New York, Ohio, Oklahoma,Pennsylvania and Texas. Each of those states, except Texas, currently impose a personal income tax. We or Atlas may do business or own property in other statesin the future. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Ourcounsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $79.2 million from the sale of 3,600,000 common units offered by this prospectus, after deductingunderwriting discounts and commissions and estimated offering expenses payable by us. Our estimates assume an initial public offering price of $24.00 percommon unit, the mid−point of the range set forth on the cover page of this prospectus, and no exercise of the underwriters’ option to purchase additional units.

Substantially all of the net proceeds from this offering will be distributed to Atlas America. If the underwriters exercise all or any portion of their option topurchase additional common units, we will use all of the net proceeds from the sale of our common units sold pursuant to the exercise of that option to fund theredemption of an equal number of common units from Atlas America. The redemption price per common unit will be equal to the price per common unit (net ofunderwriting discounts) sold to the underwriters upon exercise of their option to purchase additional common units. Please read “Security Ownership of CertainBeneficial Owners and Management.”

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and our capitalization as of September 30, 2005 on a consolidated historical basis for Atlas PipelineGP, and on a pro forma basis to reflect the following:

• this offering and the application of the net proceeds as described in “Use of Proceeds;”


• the redemption of the portion of the NOARK 7.15% notes severally guaranteed by Atlas Arkansas in connection with the NOARK acquisition;

• Atlas’ public offering of 2,700,000 common units, which was completed in November 2005 and 330,000 additional underwriter option units which wascompleted in December 2005, each at a public offering price of $42.00 per common unit, the net proceeds of which were principally used to repayindebtedness under its credit facility incurred in connection with the NOARK acquisition; and

• Atlas’ issuance of $250.0 million of 8.125% senior unsecured notes in a private placement on December 20, 2005, the net proceeds of which wereprincipally used to repay indebtedness under its credit facility.

The historical financial data of Atlas Pipeline GP presented in the table below is derived from and should be read in conjunction with Atlas Pipeline GP’shistorical financial statements, including the accompanying notes, included elsewhere in this prospectus.

As of September 30, 2005

HistoricalPro forma, as

adjusted

(in thousands)Cash and cash equivalents $ 12,035 $ 29,338

Debt:Atlas Pipeline Partners, L.P.:

Credit facility $ 183,500 $ —8.125% senior unsecured notes — 250,000NOARK 7.15% notes (1) — 39,600Other 145 145

Total debt 183,645 289,745

Minority interests (2) 227,908 348,612

Equity:Owners’ equity 5,564 5,559Accumulated other comprehensive loss (46,444) (46,444)

Total owners’ deficit (40,880) (40,885)

Total capitalization $ 370,673 $ 597,472

(1) These notes are severally guaranteed by Southwestern and amounts paid on these notes are to be paid from amounts otherwise distributable by NOARK toSouthwestern. If such amount is insufficient, Southwestern is required to make a capital contribution to NOARK for such insufficient amount.

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book valueper unit after the offering. As of September 30, 2005, after giving effect to the offering of common units and the application of the related net proceeds, andassuming the underwriters’ option to purchase additional units is not exercised, our net tangible book value was $(13.3) million, or $(0.63) per common unit. Ourtangible net book value is the sum of our owners’ equity less our pro rata share of goodwill and other intangible assets and accumulated other comprehensiveloss, based upon estimated ownership interest in those items. Purchasers of common units in this offering will experience substantial and immediate dilution innet tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

Assumed initial public offering price per common unit $ 24.00Pro forma net tangible book value per common unit before the offering (1) $ (0.76)Increase in net tangible book value per common unit attributable to purchasers in the offering 0.13

Less: Pro forma net tangible book value per common unit after the offering (2) (0.63)

Immediate dilution in tangible net book value per common unit to new investors $ 24.63

(1) Determined by dividing the total number of units (17,500,000) to be issued to Atlas America for its contribution of assets to us into our net tangible bookvalue before this offering.

(2) Determined by dividing the total number of units to be outstanding after the offering (21,100,000) and the application of the related net proceeds into our proforma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by Atlas America in respect of its common unitsand by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

Units Acquired

Total

Consideration

Number Percent Amount

General partner and affiliates (1) 17,500,000 82.9% $ (92,443,000)New investors 3,600,000 17.1% 86,400,000

Total 21,100,000 100.0% $ (6,043,000)

(1) Upon the consummation of this offering, an aggregate 17,500,000 units will be issued to Atlas America. The assets contributed by Atlas America wererecorded at historical cost in accordance with GAAP. Book value of the consideration provided by Atlas America is as follows:

Atlas America $(13,291,000)

Less: Payments to Atlas America from net proceeds of this offering 79,152,000

Total consideration $(92,443,000)

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For more detailedinformation regarding the factors and assumptions upon which our cash distribution policy is based, please see “–Assumptions and Considerations” below. Inaddition, you should read “Forward−Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical orcurrent facts and certain risks inherent in our and Atlas’ business. Unless otherwise stated, the information presented in this section assumes that theunderwriters will exercise their option to purchase additional units in full. Because the proceeds of any exercise of the underwriters’ option will be used toredeem a number of common units from our affiliates equal to the number of common units issued pursuant to the exercise of that option, the number of ourcommon units will not change upon the exercise of the option but the relative percentages of common units owned by the public and our affiliates will change.

When discussing our operating results, we are referring to the operating results of Atlas Pipeline GP, our wholly−owned subsidiary, which are presented on aconsolidated basis including Atlas. For additional information regarding our historical and pro forma operating results, you should refer to the historicalfinancial statements for the years ended December31, 2002, 2003 and 2004, our unaudited historical financial statements for the nine months endedSeptember30, 2004 and 2005 and our unaudited pro forma financial statements for the year ended December31, 2004 and the nine months ended September30,2005, included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our available cash rather than retaining it. It isimportant that you understand that our only cash−generating assets consist of our interests in Atlas from which we receive quarterly distributions. We currentlyhave no independent operations separate from those of Atlas and do not currently intend to conduct operations separate from those of Atlas. Because we believewe will have low cash requirements for operating expenses and capital investments, we believe that our investors are best served by our distribution of all of ouravailable cash as described below. Because we are not subject to an entity−level federal income tax, we have more cash to distribute to you than would be thecase were we subject to tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of ouravailable cash quarterly.

Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed atany time, including:

• Our cash distribution policy will be subject to restrictions on distributions under our anticipated new credit facility. Specifically, we anticipate that ournew credit facility will contain certain material financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictionsunder our new credit facility, or if we otherwise default under our new credit facility, we would be prohibited from making a distribution to younotwithstanding our stated cash distribution policy.

• Atlas’ cash distribution policy is subject to restrictions on distributions under its credit facility. Specifically, Atlas’ credit facility contains materialfinancial tests and covenants that it must satisfy. These financial tests and covenants are described in the prospectus under the caption “Management’sDiscussion and Analysis of Financial Condition and Results of Operations—Debt Obligations—Atlas.” Should Atlas be unable to satisfy theserestrictions under its credit facility, it would be prohibited from making cash distributions to us, which in turn would prevent us from making cashdistributions to you notwithstanding our stated cash distribution policy.

• Our general partner’s board of directors will have the authority under our partnership agreement to establish reserves for the prudent conduct of ourbusiness and for future cash distributions to our

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unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuantto our stated cash distribution policy.

• The managing board of Atlas’ general partner has the authority under Atlas’ partnership agreement to establish reserves for the prudent conduct of itsbusiness and for future cash distributions to its unitholders, and the establishment of those reserves could result in a reduction in cash distributions wewould otherwise anticipate receiving from Atlas, which in turn could result in a reduction in cash distributions to you from levels we currentlyanticipate pursuant to our stated cash distribution policy.

• While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including our cash distribution policycontained therein, may be amended by a vote of the holders of a majority of our common units. Following completion of this offering and assuming thefull exercise of the underwriters’ option to purchase additional common units, Atlas America will own approximately 80.4% of our outstandingcommon units and will have the ability to amend our partnership agreement without the approval of any other unitholders.

• Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and thedecision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

• The amount of distributions paid under Atlas’ cash distribution policy and the decision to make any distribution to its unitholders is at the discretion ofAtlas’ general partner, taking into consideration the terms of its partnership agreement.

• Under Section 17−607 of the Delaware Revised Uniform Limited Partnership Act, Atlas may not make a distribution to its partners if the distributionwould cause its liabilities to exceed the fair value of its assets and we may not make a distribution to you if the distribution would cause our liabilitiesto exceed the fair value of our assets.

• We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in general and administrativeexpenses, principal and interest payments on any current or future debt, tax expenses, working capital requirements and anticipated cash needs of us orAtlas and its subsidiaries. Please read “Risk Factors” for a discussion of these factors.

Our Cash Distribution Policy Limits Our Ability to Grow

Because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. Infact, since currently our only cash−generating assets are our interests in Atlas, our growth initially will be completely dependent upon Atlas’ ability to increase itsquarterly distribution. If we issue additional interests or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on thoseadditional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.

Atlas’ Ability to Grow is Dependent on its Ability to Access External Growth Capital

Consistent with the terms of its partnership agreement, Atlas distributes to its partners its available cash each quarter. In determining the amount of cash availablefor distribution, Atlas sets aside cash reserves, including reserves it believes prudent to maintain for the proper conduct of its business or to provide for futuredistributions. Additionally, it has relied upon external financing sources, including commercial borrowings and other debt and equity issuances, to fund itsacquisition capital expenditures. Accordingly, to the extent Atlas does not have sufficient cash reserves or is unable to finance growth externally, its cashdistribution policy will significantly impair its ability to grow. In addition, to the extent Atlas issues additional units in connection with any acquisitions orgrowth capital expenditures, the payment of distributions on those additional units may increase the risk that Atlas will be unable to maintain or increase its perunit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders. The incurrence of additional commercial or otherdebt to finance its growth strategy would result in increased interest expense to Atlas, which in turn may impact the available cash that we have to distribute toour unitholders.

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Our Initial Distribution Rate

Our Cash Distribution Policy

Upon completion of this offering, the board of directors of our general partner will adopt a cash distribution policy pursuant to which we will declare an initialdistribution of $0.225 per unit per quarter, or $0.90 per unit per year, to be paid no later than 50 days after the end of each fiscal quarter. This equates to anaggregate cash distribution of approximately $4.7 million per quarter, or approximately $19.0 million per year, based on the common units outstandingimmediately after completion of this offering.

The following table sets forth the assumed number of outstanding common units upon the closing of this offering, and the estimated per unit and aggregatedistribution amounts payable on such common units during the year following the closing of this offering at our initial distribution rate of $0.225 per commonunit per quarter ($0.90 per common unit on an annualized basis):

Distributions on Our Common Units

Number ofCommon Units One Quarter Four Quarters

Estimated distributions on publicly held common units 4,140,000 $ 931,500 $ 3,726,000Estimated distributions on common units held by Atlas America 16,960,000 3,816,000 15,264,000

Total 21,100,000 $ 4,747,500 $ 18,990,000

These distributions will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter at the anticipatedinitial distribution rate, our unitholders will not be entitled to receive such payments in the future. We will pay our distributions on or about the 20th of each ofFebruary, May, August and November to holders of record on or about the 13th of each such month. If the distribution date does not fall on a business day, wewill make the distribution on the business day immediately preceding the indicated distribution date. Any distributions received by us from Atlas related toperiods prior to the closing of this offering will be distributed entirely to Atlas America. In May 2006, we expect to pay a distribution to our unitholders equal tothe initial quarterly distribution prorated for the portion of the quarter ending March 31, 2006 that we are public.

Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Underour partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of cashreserves established by our general partner to, among other things:

• provide for the proper conduct of our business;

• comply with applicable law, any of our debt instruments or other agreements; or

• provide funds for distributions to our unitholders for any one or more of the next four quarters.Atlas’ Cash Distribution Policy

Like us, Atlas has adopted a cash distribution policy that requires it to distribute its available cash to its unitholders on a quarterly basis. Under Atlas’ partnershipagreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from Atlas’ business in excess of the amount its general partnerreasonably determines is necessary or appropriate to provide for the conduct of its business, comply with applicable law, any of its debt instruments or otheragreements or provide for future distributions to its unitholders for any one or more of the next four quarters. Atlas’ determination of available cash takes intoaccount the possibility of establishing cash reserves in some quarterly periods that it may use to pay cash distributions in other quarterly periods, thereby enablingit to maintain relatively consistent cash distribution levels even if its business experiences fluctuations in its cash from operations due to seasonal and cyclicalfactors. Atlas’ determination of available cash also allows it to maintain reserves to provide funding for its growth opportunities. Atlas makes its quarterlydistributions from cash generated from its transmission, gathering and processing operations and those distributions have grown over time as its business hasgrown,

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as a result of a substantial acquisition program and internal growth projects that are funded through external financing sources.

The following table sets forth the amount of quarterly cash distributions Atlas declared on its ownership interests for the periods indicated. The actual cashdistributions (i.e., payments to the partners of Atlas) occur within 45 days after the end of such quarter. Atlas has an established historical record of payingquarterly cash distributions to its partners.

Atlas Cash Distribution History

Distributions on L.P. Units Distributions on2.0% General

Partner

Distributions onIncentive

DistributionTotal Atlas

CashPer Unit Total Interest Rights Distributions

(in thousands, except per unit)20031st Quarter $ 0.560 $ 1,827 $ 40 $ 95 $ 1,9622nd Quarter $ 0.580 $ 2,526 $ 55 $ 155 $ 2,7363rd Quarter $ 0.620 $ 2,700 $ 60 $ 269 $ 3,0294th Quarter $ 0.625 $ 2,721 $ 62 $ 290 $ 3,07320041st Quarter $ 0.630 $ 2,743 $ 63 $ 311 $ 3,1172nd Quarter $ 0.630 $ 3,216 $ 73 $ 365 $ 3,6543rd Quarter $ 0.690 $ 4,971 $ 120 $ 939 $ 6,0304th Quarter $ 0.720 $ 5,187 $ 130 $ 1,150 $ 6,46720051st Quarter $ 0.750 $ 5,404 $ 138 $ 1,362 $ 6,9042nd Quarter $ 0.770 $ 7,319 $ 190 $ 1,983 $ 9,4923rd Quarter $ 0.810 $ 7,711 $ 205 $ 2,360 $ 10,2764th Quarter $ 0.830 $ 10,416 $ 282 $ 3,356 $ 14,054In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.225 per common unit perquarter through the quarter ending December 31, 2006. In those sections we present two tables, including:

• Our “Unaudited Pro Forma Available Cash,” in which we present the amount of pro forma available cash that we would have had available fordistribution to our unitholders with respect to the year ended December 31, 2004 and the twelve months ended September 30, 2005. Our calculation ofpro forma available cash in this table should only be viewed as a general indication of the amount of cash available that we might have generated hadwe been formed in an earlier period.

• Our “Estimated Cash Available for Distribution” in which we present our estimate of the minimum Adjusted EBITDA necessary for us to havesufficient cash available for distribution to pay distributions at the initial distribution rate on all the outstanding common units for each quarter for theyear ending December 31, 2006. In “Assumptions and Considerations” below, we also present our assumptions underlying our belief that Atlas willgenerate this minimum Adjusted EBITDA.

We do not as a matter of course make public projections as to future sales, earnings, or other results. However, we have prepared the prospective financialinformation set forth below to present the tables entitled “Unaudited Pro Forma Available Cash” and “Estimated Cash Available for Distribution.” Theaccompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute ofCertified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currentlyavailable estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that Atlas cangenerate the minimum Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay a distribution on the common units at the initialdistribution rate. However, this information is not fact and should not be relied upon as being necessarily indicative of

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future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospectivefinancial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability. Accordingly,they assume no responsibility for, and disclaim any association with, the prospective financial information.

Our pro forma available cash for the twelve months ended December 31, 2004 would not have been sufficient to pay the initial quarterly distribution of$0.225 per unit on the common units to be outstanding following the completion of this offering.

If we had completed the transactions contemplated in this prospectus on January 1, 2004, our pro forma available cash deficit generated during fiscal 2004 wouldhave been approximately $2.4 million. This amount would have been insufficient by approximately $21.4 million to pay the full initial distribution amount on allour units.

Our pro forma available cash for the twelve months ended September30, 2005 would not have been sufficient to pay the initial quarterly distribution of$0.225 per unit on the common units to be outstanding following the completion of this offering.

If we had completed the transactions contemplated in the prospectus on October 1, 2004, our pro forma available cash for the twelve months endedSeptember 30, 2005 would have been approximately $9.0 million. This amount would have been insufficient by approximately $10.0 million to pay the fullinitial distribution amount on all units.

We believe that we will have sufficient cash available for distribution to pay the full quarterly distributions at the initial distribution rate of $0.225 per unit on allthe outstanding common units for each quarter for the year ending December 31, 2006. See “Assumptions and Considerations” below for the specificassumptions underlying this belief.

Pro forma cash available for distribution includes estimated incremental general and administrative expenses we will incur as a result of being a publicly tradedlimited partnership, such as costs associated with annual and quarterly reports to unitholders, tax return and Schedule K−1 preparation and distribution, investorrelations, registrar and transfer agent fees, director compensation, accounting and audit fees and incremental insurance costs, including director and officerliability and business interruption insurance. We expect these incremental general and administrative expenses initially to total approximately $1.0 million peryear.

The pro forma financial statements, upon which pro forma cash available for distribution is based, do not purport to present our results of operations had thetransactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accountingconcept, while our pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distributionshown above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a generalindication of the amount of cash available for distribution that we might have generated had we been formed in earlier periods.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2004 and for the twelve months ended September 30, 2005, the amount ofavailable cash that would have been available for distributions to our unitholders, assuming in each case that this offering had been consummated at thebeginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

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Unaudited Pro Forma Available Cash of Atlas Pipeline Holdings, L.P.

Year EndedDecember31,

2004

Twelve MonthsEnded

September30, 2005

(in thousands, except per unit data and

ratios)

Net Cash Provided by Operating Activities (1) $ 11,311 $ 32,825Plus (minus):Cash interest expense 1,901 7,599Non−recurring gain on arbitration settlement, net (2) (1,457) (4,306)Net changes in working capital accounts, including net changes in price risk management assets and liabilities (3) 12,595 9,159

Adjusted EBITDA (4) 24,350 45,277Plus: Pro forma acquisition adjustment to Adjusted EBITDA (5) 34,411 24,397

Pro forma Adjusted EBITDA 58,761 69,674Less:Pro forma cash interest expense (6) (20,313) (20,313)Maintenance capital expenditures (7) (1,516) (1,782)Expansion capital expenditures (8) (8,527) (38,361)Estimated maintenance capital expenditures of acquisitions (9) (1,615) (829)Pro forma distributions to non−affiliated owners of Atlas (10) (36,747) (36,747)Estimated incremental general and administrative expense (11) (1,000) (1,000)Plus:Borrowings under Atlas credit facility for expansion capital expenditures (12) 8,527 38,361

Pro forma available cash at Atlas Pipeline Holdings, L.P. $ (2,430) $ 9,003

Expected Cash Distributions: (13)Expected distribution per unit $ 0.90 $ 0.90

Distributions to public common unitholders $ 3,726 $ 3,726Distributions to common units held by our affiliates 15,264 15,264

Total distributions $ 18,990 $ 18,990

Shortfall (14) $ (21,420) $ (9,987)

Debt Covenant Ratios:Atlas

Funded Debt/EBITDA (15) 4.3x 3.5xEBITDA/Interest Expense (15) 3.0x 3.6xSenior Secured Debt/EBITDA (15) 0.1x 0.1x

(1) Reflects net cash provided by operating activities of Atlas Pipeline Holdings, L.P., derived from Atlas Pipeline GP’s historical consolidated financialstatements for the periods indicated without giving pro forma effect to the transactions described in footnote (5).

(2) Represents the non−recurring net gain recognized in connection with the fourth quarter 2004 settlement associated with Atlas’ terminated attempt to acquireAlaska Pipeline Company. Atlas settled the matter in the fourth quarter 2004 and received $5.5 million.

(3) Atlas utilizes its $225.0 million credit facility to satisfy its working capital needs, thereby allowing it to avoid using cash flow available for distribution tosatisfy working capital requirements. Therefore, we do not reflect any adjustments to cash available for distributions as a result of these requirements. Atlasis unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “workingcapital borrowings” under its partnership agreement.

(4) EBITDA represents net income before net interest expense, income taxes, depreciation and amortization and minority interest in Atlas. Adjusted EBITDA iscalculated by adding to EBITDA other non−cash items such as compensation expenses associated with unit issuances to directors and employees. EBITDAand Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Adjusted EBITDA doesnot reflect approximately $1.0 million

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of additional general and administrative expense we expect to incur in connection with us being a public company after this offering.

(5) Reflects pro forma adjustments for Atlas’ acquisitions of NOARK in October 2005, Elk City in April 2005, and Spectrum in July 2004. These acquisitionswere accounted for under the purchase method of accounting. Accordingly, the results of operations for these acquisitions are reflected in Atlas’ historicaloperating results beginning on the day it closed the transactions. We have included the results of these acquisitions in our results on a pro forma basis as ifthe operations were acquired on January 1, 2004. The financial information for these acquisitions was derived from audited financial statements and proforma financial statements included in this prospectus. Our independent auditors have not examined, compiled, or otherwise applied procedures to our proforma financial statements, and accordingly, do not express an opinion or any other assurance on the pro forma financial information set forth below. Thepro forma financial data should not be considered indicative of the historical results we would have had or the future results that we will have after thisoffering. We have set forth below a summary of our pro forma adjustments to Adjusted EBITDA to reflect Atlas’ acquisitions (in thousands):

Year Ended December31, 2004

Historical

Spectrum Elk City NOARKPro Forma

Adjustments Total

Net income $ 55,977 $ 7,583 $ 3,429 $ (69,423) $ (2,434)Minority interest in Atlas — — — 429 429Depreciation and amortization 1,638 2,153 3,249 5,292 12,332Interest expense 1,712 — 5,287 17,085 24,084Income tax expense 32,319 — 2,162 (34,481) —Non−cash compensation expense 6,369 — — (6,369) —Gain recognized upon sale of Spectrum by previous owner (89,109) — — 89,109 —

Total adjustments $ 8,906 $ 9,736 $14,127 $ 1,642 $34,411

Twelve Months Ended September30, 2005

Historical

Pro FormaElk City NOARK Adjustments Total

Net income $ 4,893 $ 5,373 $ (11,971) $ (1,705)Minority interest in Atlas — — 2,623 2,623Depreciation and amortization 1,287 3,320 2,046 6,653Interest expense — 4,892 11,934 16,826Income tax expense — 3,464 (3,464) —

Total adjustments $ 6,180 $17,049 $ 1,168 $24,397

(6) Reflects an increase to interest expense of approximately $18.4 million and $12.7 million for the year ended December 31, 2004 and the twelve monthsended September 30, 2005, respectively, as a result of interest expense related to Atlas’ issuance of $250.0 million of its 8.125% senior notes. This amountdoes not reflect interest expense on NOARK’s $39.6 million of 7.15% notes, for which our minority interest partner in NOARK is liable. Under theNOARK partnership agreement, payments on the NOARK notes will be made from amounts otherwise distributable to the minority interest partner and, ifthat amount is insufficient, the minority interest partner is required to make a capital contribution to NOARK.

(7) Reflects actual maintenance capital expenditures during the period.

(8) Expansion capital expenditures for the year ended December 31, 2004 and the twelve months ended September 30, 2005 were $8.5 million and $38.4million, respectively. The expansion capital expenditures for the year ended December 31, 2004 include gathering system expansions and compressorupgrades of the Velma and Appalachian gathering systems. The $38.4 million of expansion capital expenditures for the twelve months ended September 30,2005 include expansions of the Velma and Elk City gathering systems and processing facilities to accommodate new wells drilled in their service areas andcompressor upgrades and expansions of the Appalachian gathering system.

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(9) Includes estimated adjustments to maintenance capital expenditures of $1.6 million and $0.8 million for the year ended December 31, 2004 and the twelvemonths ended September 30, 2005, respectively, to reflect pro forma maintenance capital expenditure activity for recently completed acquisitions. Theseestimated adjustments are derived based on Atlas’ experience in operating these assets as well as the specific characteristics of the businesses Atlas hasacquired.

(10) Reflects the cash distributions from Atlas to its unitholders other than us based upon the most recent announced quarterly distribution of $0.83 per limitedpartner unit or $3.32 per limited partner unit on an annualized basis.

(11) Reflects approximately $1.0 million in incremental ongoing expenses associated with being a publicly−traded partnership, including, among other things,estimated incremental costs associated with annual and quarterly reports to unitholders, tax return and Schedule K−1 preparation and distribution, investorrelations, registrar and transfer agent fees, director compensation, accounting and audit fees and incremental insurance costs, including director and officerliability and business interruption insurance.

(12) Reflects borrowings incurred under Atlas’ credit facility to finance its expansion capital expenditures. Because Atlas distributes substantially all of itsavailable cash on a quarterly basis, Atlas has historically financed its growth capital expenditures through the use of external financing alternatives,including borrowings under its credit facility and the public capital markets. In the future, Atlas anticipates that it will continue to utilize these externalsources of financing to fund its acquisition growth strategy and expects to refinance all of its debt as it matures.

(13) The table below sets forth the assumed number of outstanding common units upon the closing of this offering, assuming the full exercise of theunderwriters’ option to purchase additional common units, and the estimated per unit and aggregate distribution amounts payable on such common unitsduring the year following the closing of this offering at our initial distribution rate:

Distributions on Our Common Units

Number ofCommon

Units Per Unit Aggregate

Estimated distributions on publicly held common units 4,140,000 $ 0.90 $ 3,726,000Estimated distributions on common units held by our affiliates 16,960,000 $ 0.90 15,264,000

Total 21,100,000 $18,990,000

(14) We believe that we will have sufficient cash available for distribution to pay the full quarterly distributions at the initial distribution rate of $0.225 per uniton all the outstanding common units for each quarter for the year ending December 31, 2006. See “Assumptions and Considerations” below for the specificassumptions we are making in projecting that we will have sufficient available cash for the four quarters in the year ending December 31, 2006.

(15) Atlas’ credit facility requires it to maintain a ratio of senior secured debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) of notmore than 6.0 to 1.0, reducing to 5.75 to 1.0 on March 31, 2006, 4.5 to 1.0 on June 30, 2006, and 4.0 to 1.0 on September 30, 2006; a funded debt (asdefined in the credit facility) to EBITDA ratio of not more than 6.0 to 1.0, reducing to 5.75 to 1.0 on March 31, 2006 and to 4.5 to 1.0 on June 30, 2006, andan interest coverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 3.0 to 1.0 on March 31, 2006. The credit facility definesEBITDA to include pro forma adjustments, acceptable to the administrator of the facility, following material acquisitions. The definition of EBITDAcontained in the credit facility is substantially similar to the definition of Adjusted EBITDA used in this prospectus, except that: (1) the credit facilitydefinition of EBITDA includes net gain or loss on arbitration settlement, while the definition of Adjusted EBITDA excludes net gain or loss on arbitrationsettlement as a non−recurring item, and (2) the credit facility definition of EBITDA includes EBITDA of NOARK only to the extent of cash distributionsfrom NOARK, while the definition of Adjusted EBITDA includes Atlas’ percentage interest in NOARK’s EBITDA. The ratios described above includeonly the operations of Atlas and its subsidiaries, and exclude our operations and those of our subsidiaries that are not subsidiaries of Atlas.

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Estimated Cash Available for Distributions

In order to pay the quarterly distribution to our common unitholders at our initial distribution rate of $0.225 per unit per quarter for each quarter in the periodending December 31, 2006, we estimate that Atlas must generate at least $79.4 million in Adjusted EBITDA during the twelve months ending December 31,2006. We refer to this amount as “Estimated Minimum Adjusted EBITDA.” Estimated Minimum Adjusted EBITDA is intended to be an indicator or benchmarkof the amount management considers to be the lowest amount of Adjusted EBITDA necessary to generate sufficient available cash for us to make cashdistributions to our common unitholders at our initial distribution rate of $0.225 per common unit per quarter (or $0.90 per common unit per year). The EstimatedMinimum Adjusted EBITDA should not be viewed as management’s projection of the actual Adjusted EBITDA that will be generated during 2006.

Estimated Minimum Adjusted EBITDA of $79.4 million exceeds pro forma Adjusted EBITDA for the year ended December 31, 2004 by approximately $20.7million and pro forma Adjusted EBITDA for the twelve months ended September 30, 2005 by approximately $9.7 million. We believe that Atlas will generatethe Estimated Minimum Adjusted EBITDA for the year ending December 31, 2006. In “—Assumptions and Considerations” below, we discuss the majorassumptions underlying our belief that Atlas will be able to generate the Estimated Minimum Adjusted EBITDA and we will have sufficient available cash to paydistributions at the initial distribution rate. We can give you no assurance that our assumptions will be realized or that Atlas will generate the EstimatedMinimum Adjusted EBITDA or the expected level of available cash, in which event we will not be able to pay the initial quarterly distribution on our commonunits. When considering how we calculate estimated cash available for distribution, please keep in mind all the risk factors and other cautionary statements underthe heading “Risk Factors” and elsewhere in the prospectus, which discuss factors that could cause cash available for distribution to vary significantly from ourestimates.

As shown in the table below, we have also determined that if Atlas achieves the Estimated Minimum Adjusted EBITDA, Atlas would be permitted under theterms of its credit facility to make its distributions to its unitholders. In addition, we expect that we will be permitted to make distributions at the initialdistribution rate under our anticipated credit agreement.

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Atlas Pipeline Holdings, L.P. Estimated Cash Available for Distribution

Four Fiscal Quarters EndingDecember31, 2006

(in thousands, except per unit dataand ratios)

Estimated Minimum Adjusted EBITDA (1) $ 79,420Less:Cash interest expense (2) (20,283)Maintenance capital expenditures (3) (2,400)Expansion capital expenditures (4) (45,537)Acquisition capital expenditures (5) —Incremental general and administration expense (6) (1,000)Distributions to non−affiliated owners of Atlas (7) (36,747)Plus:Sources for expansion capital expenditures (8) 45,537

Estimated Available Cash at Atlas Pipeline Holdings, L.P. $ 18,990

Expected Cash Distributions by Atlas Pipeline Holdings, L.P.Expected distribution per common unit $ 0.90

Distributions to our public common unitholders $ 3,726Distributions to common units held by affiliates 15,264

Total distributions paid to our common unitholders (9) $ 18,990

Debt Covenant RatiosAtlas

Funded Debt / EBITDA (10) 3.4xEBITDA / Interest Expense (10) 3.9xSenior Secured Debt / EBITDA (10) 0.3x

(1) We believe that Estimated Minimum Adjusted EBITDA for the year ending December 31, 2006 will be approximately $79.4 million. Estimated MinimumAdjusted EBITDA is approximately $20.7 million more than the pro forma Adjusted EBITDA Atlas generated for the year ended December 31, 2004 andapproximately $9.7 million more than the pro forma Adjusted EBITDA Atlas generated for the twelve months ended September 30, 2005. Please see“—Assumptions and Considerations” for a discussion of the assumptions underlying our belief that we will be able to generate sufficient available cash forus to make cash distributions to our common unitholders at our initial distribution rate.

(2) Our estimated cash interest expense is comprised of the following components:

(i) Approximately $20.3 million associated with Atlas’ $250.0 million of 8.125% senior unsecured notes;

(ii) Approximately $0.7 million attributable to capital expenditures, a portion of which will be financed with cash on hand, and a portion of which willbe financed with borrowings under Atlas’ credit facility; and

(iii) Offset by $0.7 million of capitalized interest related to the construction of the Sweetwater gas plant and associated gathering system.

(3) We currently expect that our estimated maintenance capital expenditures will be approximately $2.4 million for the year ending December 31, 2006 incomparison to pro forma maintenance capital expenditures of $3.1 million and $2.6 million for the year ended December 31, 2004 and the twelve monthsended September 30, 2005, respectively. The decrease in the estimated maintenance capital expenditures for the year ending December 31, 2006 primarilyreflects the completion of maintenance projects during the prior historical periods.

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(4) This reflects our estimated expenditure of $45.5 million for expansion capital for the year ending December 31, 2006. Our estimated expansion capitalexpenditures of approximately $45.5 million for the year ending December 31, 2006 includes approximately $30.0 million associated with the constructionof Atlas’ Sweetwater gas plant and associated gathering system and $15.5 million for well connections and other internal expansion projects relating toAtlas’ transmission, processing, and treatment operations. Our estimated $45.5 million of expansion capital expenditures for the year ending December 31,2006 as compared to the expansion capital expenditures for the year ended December 31, 2004 and the twelve months ended September 30, 2005 representsan increase of approximately $37.0 million and approximately $7.1 million, respectively. The increased need for future expansion capital expenditures isprimarily a result of the construction of the Sweetwater gas plant and an increase in well connections due to increased drilling activity in Atlas’ area ofoperations.

(5) Consistent with its acquisition strategy, Atlas is continuously pursuing strategic acquisitions that it expects to be accretive to its earnings. Since Atlas’inception in January 2000 through November 2005, Atlas has consummated five acquisitions for an aggregate purchase price of approximately $516.7million. While Atlas expects to continue to pursue acquisitions in the next twelve months, because of the uncertain nature of the acquisition environment, wehave not included an estimate of future acquisition capital expenditure requirements. If Atlas is successful in completing additional acquisitions, Atlasanticipates its primary source of consideration will be through commercial borrowings, other debt and common unit issuances. While the initial funding ofits acquisitions may consist of debt financing, Atlas’ financial strategy is to finance acquisitions equally with equity and debt, and Atlas would expect torepay such debt with proceeds of equity issuances to achieve this relatively balanced financing ratio. If Atlas is unable to finance its growth through externalsources or is unable to achieve its targeted debt/equity ratios, our cash available to pay distributions may be negatively impacted.

(6) Reflects approximately $1.0 million in incremental ongoing expenses associated with being a publicly−traded partnership, including, among other things,estimated incremental costs associated with annual and quarterly reports to unitholders, tax return and Schedule K−1 preparation and distribution, investorrelations, registrar and transfer agent fees, director compensation, accounting and audit fees and incremental insurance costs, including director and officerliability and business interruption insurance.

(7) Reflects the cash distributions from Atlas to its unitholders other than us based upon the most recent declared quarterly distribution of $0.83 per limitedpartner unit or $3.32 per limited partner unit on an annualized basis.

(8) Atlas has historically financed internal growth and acquisitions through the use of cash on hand together with external financing sources, includingborrowings under its credit facility and the issuance of debt and equity securities. Atlas anticipates that it will use cash on hand together with availablecapacity under its credit facility to fund its projected $45.5 million of expansion capital expenditures.

(9) Represents the amount required to fund distributions to our unitholders based upon the declared annualized distribution of $0.90 per unit and assuming theunderwriters’ option to purchase additional common units has been exercised in full.

(10) Atlas’ credit facility requires it to maintain a ratio of senior secured debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) of notmore than 6.0 to 1.0, reducing to 5.75 to 1.0 on March 31, 2006, 4.5 to 1.0 on June 30, 2006 and 4.0 to 1.0 on September 30, 2006; a funded debt (as definedin the credit facility) to EBITDA ratio of not more than 6.0 to 1.0, reducing to 5.75 to 1.0 on March 31, 2006 and to 4.5 to 1.0 on June 30, 2006, and aninterest coverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 3.0 to 1.0 on March 31, 2006. The credit facility definesEBITDA to include pro forma adjustments, acceptable to the administrator of the facility, following material acquisitions. The definition of EBITDAcontained in the credit facility is substantially similar to the definition of Adjusted EBITDA used in this prospectus, except that: (1) the credit facilitydefinition of EBITDA includes net gain or loss on arbitration settlement, while the definition of Adjusted EBITDA excludes net gain or loss on arbitrationsettlement as a non−recurring item, and (2) the credit facility definition of EBITDA includes EBITDA of NOARK only to the extent of cash distributionsfrom

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NOARK, while the definition of Adjusted EBITDA includes Atlas’ percentage interest in NOARK’s EBITDA. The ratios described above include only theoperations of Atlas and its subsidiaries, and exclude our operations and those of our subsidiaries that are not subsidiaries of Atlas.

Assumptions and Considerations

While we believe that the following assumptions are generally consistent with the actual performance of Atlas since its acquisitions of Elk City and NOARK in2005 and Spectrum in 2004, and are reasonable in light of our current beliefs concerning future events, the assumptions are inherently uncertain and are subjectto significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate.If our assumptions are not realized, the actual available cash that Atlas generates, and thus the available cash of Atlas Pipeline GP could be substantially less thanthat currently expected and could, therefore, be insufficient to permit us to make our initial quarterly and annual distributions on our units, in which event themarket price of our units may decline materially. Consequently, the statement that we believe that we will have sufficient available cash to pay the initialdistribution on our units for each quarter through December 31, 2006 should not be regarded as a representation by us or the underwriters or any other person thatwe will make such a distribution. When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading “RiskFactors” in this prospectus.

We believe that our interests in Atlas will generate sufficient cash flow to enable us to pay our initial quarterly distribution of $0.225 per unit on all of our unitsfor the four quarters ending December 31, 2006. Our belief is based on a number of current assumptions that we believe to be reasonable over the next fourquarters.

Distribution Rate of Atlas. Our estimate of cash distributions to be received from Atlas during the twelve months ending December 31, 2006 assumes thatAtlas will continue to pay its recently declared quarterly distribution of $0.83 per common unit over the next four quarters and that the amount of cashdistributions we receive from Atlas will be sufficient to allow us to pay total distributions to our unitholders of approximately $19.0 million. We have assumedthat Atlas Pipeline GP will maintain its 2.0% general partner interest in Atlas by making proportionate cash contributions to Atlas in connection with Atlas’equity issuances.

Operating Performance of Atlas. The primary determinant of Adjusted EBITDA is cash flow generated by the operations of Atlas. In order for us to paydistributions at the initial distribution rate, we believe that Atlas must achieve Estimated Minimum Adjusted EBITDA of $79.4 million for the twelve monthsending December 31, 2006.

Our estimates of Estimated Minimum Adjusted EBITDA are based on several general assumptions related to Atlas’s operating performance, including:

Commodity Prices. Our estimate of Adjusted EBITDA for the twelve months ending December 31, 2006 assumes that there will not be any significant changesin the commodity prices Atlas received for natural gas, NGLs and condensate over the twelve months ended September 30, 2005, taking into account Atlas’hedge positions. We have assumed that for any hedges that expire in 2006, Atlas will realize the average prices it received during the twelve month period endedSeptember 30, 2005, such average prices including the impact of hedge prices during that time.

In its Mid−Continent operations, for the twelve months ended September 30, 2005, taking into account Atlas’ hedge positions during that period, Atlas realizedaverage commodity prices of approximately $6.34 per Mcf of natural gas, approximately $0.77 per gallon of NGLs and approximately $51.92 per barrel ofcondensate in its Mid−Continent operations. Atlas has hedged portions of its Mid−Continent natural gas, NGL and condensate volumes for fixed prices forvarious periods through 2008. The following table summarizes Atlas’ hedge positions for its Mid−Continent volumes through December 31, 2006:

Commodity

Average percentage ofanticipated volumes

hedged Average fixed price

Natural gas 47% $6.63/MMbtuNGLs 54% $0.68/gallonCondensate 69% $49.25/Bbl

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In its Appalachian operations, Atlas is a party to natural gas gathering agreements with Atlas America under which Atlas receives gathering fees generally equalto a percentage, typically 16%, of the selling price of the natural gas it transports. Atlas was paid gathering fees based on an average price of approximately $6.85per Mcf of natural gas during the twelve months ended September 30, 2005. Atlas is the beneficiary of, and consults with Atlas America with respect to, thehedging program Atlas America has established for its Appalachian natural gas production. Atlas America’s hedging program impacts the gathering fees Atlasearns under its natural gas gathering agreements with Atlas America. We have assumed that Atlas will receive gathering fees based on an average price of $6.85per Mcf on Atlas America’s unhedged natural gas production and $9.00 per Mcf on Atlas America's hedged natural gas production through December 31, 2006.

Volumes. Our estimate of Adjusted EBITDA for the twelve months ending December 31, 2006 assumes that Atlas’ transportation, gathering and processingvolumes will approximate those shown in the following table. For comparison purposes, we have shown the corresponding pro forma volumetric data for thetwelve months ended September 30, 2005:

Twelve MonthsEnded

Twelve MonthsEnding

September30, 2005 December31, 2006

Appalachia:Average Throughput Volume (Mcf/d) 54,885 54,885

Mid−Continent:Velma Residue Gas Volume (Mcf/d) 50,231 50,231Velma NGL and Condensate Volume (Bbl/d) 6,776 6,776Elk City Gathered Gas Volume (Mcf/d) 251,050 251,050Elk City NGL and Condensate Volume (Bbl/d) 5,491 5,491NOARK Average Throughput (Mcf/d) 168,540 225,000Sweetwater Gathered Volume (Mcf/d) (1) — 30,000Sweetwater NGL and Condensate Volume (Bbl/d) (2) — 1,866

(1) Represents volumes currently being gathered in the Elk City area that are incremental to the 251,050 Mcf/d of Elk City gathered gas volumes. Atlascurrently earns a gathering fee on this 30,000 Mcf/d but does not currently earn any processing fees due to the fact that the Elk City plant is currentlyprocessing at maximum capacity and is unable to process those volumes.

(2) Atlas anticipates that the Sweetwater gas plant will be operational beginning in the third quarter of 2006. These volumes represent the NGL and condensateproduction once the plant becomes operational from the 30,000 Mcf/d of volumes currently being gathered in the Elk City area, which are assumed toremain flat for 2006.

Our Estimated Minimum Adjusted EBITDA assumes that Atlas’ overall operating volumes in Velma and Elk City will remain at the same level as for the twelvemonths ended September 30, 2005. Our estimate includes 30,000 Mcf/d of volumes currently being gathered in the Elk City area that are incremental to the251,050 Mcf/d of Elk City gathered gas volumes. In addition, our estimate includes NGL and condensate volumes relating to these incremental volumesproduced after the Sweetwater gas plant becomes operational.

Our estimate also assumes that Atlas’ gathering and transportation volumes related to NOARK will increase in 2006 as a result of increased drilling activity inthe Mid−Continent area, including in the Fayetteville Shale play in the Arkoma basin. NOARK volumes are also expected to increase as a result of a positivebasis spread across the Ozark Gas Transmission system.

Other Assumptions Used in Determining Estimated Minimum Adjusted EBITDA

• Atlas will generate $108.1 million of gross margin through the operation of its Mid−Continent and Appalachia business segments, as compared to$100.6 million of pro forma gross margin for the twelve months ended September 30, 2005;

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• Atlas’ plant operating expenses are expected to be approximately $11.3 million for the twelve months ending December 31, 2006, as compared to $11.1million of pro forma plant operating expenses for the twelve months ended September 30, 2005;

• Atlas’ transportation and compression expenses are expected to be approximately $7.4 million for the twelve months ending December 31, 2006, ascompared to $7.5 million of pro forma transportation and compression expenses for the twelve months ended September 30, 2005;

• Atlas’ general and administrative expenses are expected to be approximately $14.4 million for the twelve months ending December 31, 2006, ascompared to $14.6 million of pro forma general and administrative expenses for the twelve months ended September 30, 2005;

• Atlas’ maintenance capital expenditures are expected to be approximately $2.4 million for the twelve months ending December 31, 2006;

• Atlas’ growth capital expenditures are expected to be approximately $45.5 million for the twelve months ending December 31, 2006;

• Based on Atlas’ current businesses, Atlas will borrow approximately $23.4 million under its $225 million revolving credit facility;

• Atlas’ average interest rate on its $225 million revolving credit facility will be approximately 7.0%;

• Atlas’ average interest rate related to its $250 million senior unsecured notes will be 8.125%;

• there will not be any new federal, state or local regulation of portions of the energy industry in which we and Atlas operate, or a new interpretation ofexisting regulation, that will be materially adverse to our or Atlas’ business; and

• market, regulatory, insurance and overall economic conditions will not change substantially.

Our Sources of Distributable Cash

Our only cash−generating assets currently consist of our partnership interests in Atlas. Therefore, our cash flow and resulting ability to make distributionsinitially will be completely dependent upon the ability of Atlas to make distributions in respect of those interests and rights. The actual amount of cash that Atlaswill have available for distribution will primarily depend on the amount of cash it generates from operations. The actual amount of this cash will fluctuate fromquarter to quarter based on certain factors, including:

• the level of capital expenditures Atlas makes;

• the cost of capital used to fund acquisitions;

• debt service requirements;

• fluctuations in cash flow generated by Atlas’ operating activities;

• prevailing economic conditions;

• fluctuations in working capital needs;

• restrictions on distributions contained in Atlas’ credit facility and senior notes; and

• the amount, if any, of cash reserves established by Atlas’ general partner in its discretion for the proper conduct of its business.As Atlas makes quarterly distributions to its partners, we receive our share of such distributions in proportion to our ownership interest in Atlas. Uponcompletion of this offering, we will own, directly or indirectly:

• a 100% ownership interest in the general partner of Atlas, which owns:

o a 2.0% general partner interest in Atlas, which entitles it to receive 2.0% of the cash distributed by Atlas;61


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o all of the incentive distribution rights in Atlas, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cashdistributed by Atlas as it reaches certain target distribution levels in excess of $0.42 per Atlas unit in any quarter; and

o 1,641,026 common units of Atlas, representing an approximate 12.8% limited partner interest in Atlas.

Our Incentive Distribution Rights Related to Atlas’ Cash Distributions. The incentive distribution rights we own in Atlas represent our right to receive anincreasing percentage of Atlas’ quarterly distributions of available cash from operating surplus after Atlas has made cash distributions in excess of its minimumquarterly distribution level. Atlas will distribute any available cash from operating surplus for that quarter among its unitholders and Atlas’ general partner in thefollowing manner:

• First, 98.0% to all unitholders of Atlas pro rata and 2.0% to the general partner, until Atlas has distributed $0.42 for each outstanding common unit;

• Second, 85.0% to all unitholders of Atlas, pro rata, 2.0% to the general partner and 13.0% to us, until a hypothetical unitholder has received a total of$0.52 per unit for that quarter, in addition to any distributions to Atlas’ common unitholders to eliminate any cumulative arrearages in payment of theminimum quarterly distribution on the common units (“second target distribution”);

• Third, 75.0% to all unitholders of Atlas, pro rata, 2.0% to the general partner and 23.0% to us, until each unitholder has received a total of $0.60 perunit for that quarter, in addition to any distributions to Atlas’ common unitholders to eliminate any cumulative arrearages in payment of the minimumquarterly distribution on the common units (“third target distribution”); and

• Thereafter, 50.0% to all unitholders of Atlas, pro rata, 2.0% to the general partner and 48.0% to us.Hypothetical Allocations of Distributions to Our Unitholders and Atlas’ Unitholders. The table set forth below demonstrates the percentage allocations among(i) the owners of Atlas, other than us, and (ii) Atlas Pipeline Holdings, L.P. as a result of certain assumed quarterly distribution payments per common units madeby Atlas, including the target distribution levels contained in Atlas’ partnership agreement. This information assumes:

• Atlas has 12,549,266 common units outstanding; and

• we own (i) 1,641,026 Atlas common units, comprising approximately 12.8% of the outstanding common units in Atlas, (ii) a 2.0% general partnerinterest in Atlas and (iii) the incentive distribution rights in Atlas.

The percentage interests shown for us and the other Atlas unitholders for the minimum quarterly distribution amount are also applicable to distribution amountsthat are less than the minimum quarterly distribution. The amounts presented below are intended to be illustrative of the way in which we are entitled to anincreasing share of distributions from Atlas as total distributions from Atlas increase and are not intended to represent a prediction of future performance basedupon 12,549,266 Atlas limited partnership units outstanding at December 31, 2005.

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Distribution Level

Atlas QuarterlyDistribution Per

Unit

Distributions toOwners of Atlas

Other than Us as aPercentage of Total

Distributions

Distributions to Usas a Percentage ofTotal Distributions

(1)

Minimum Quarterly Distribution $ 0.42 85.2% 14.8%Second Target Distribution $ 0.52 82.6% 17.4%Third Target Distribution $ 0.60 79.6% 20.4%Current Distribution $ 0.83 64.4% 35.6%

(1) Includes distributions made with respect to our 2.0% general partner interest (aggregate), our approximate 12.8% limited partner interest in Atlas and ourright to receive incentive payments.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

We were formed in December 2005 and therefore do not have any historical financial statements. Since we will own and control Atlas Pipeline Partners GP,LLC, the general partner of Atlas, the selected financial and operating data statements presented below are of Atlas Pipeline Partners GP, LLC on a consolidatedbasis, including Atlas.

The following table sets forth selected financial data as of and for the period from inception to December 31, 2000 and the years ended December 31, 2001,2002, 2003 and 2004 and the nine months ended September 30, 2004 and 2005. The historical financial data of Atlas Pipeline GP were derived from the auditedconsolidated financial statements for each of the years ended December 31, 2002, 2003 and 2004 and at December 31, 2003 and 2004, which have been auditedby Grant Thornton LLP, an independent registered public accounting firm. The historical financial data of Atlas Pipeline GP were derived from the consolidatedfinancial statements which are not included in this prospectus, for each of the years ended December 31, 2000 and 2001 and at December 31, 2000 and 2001. Wederived the financial data as of and for the nine months ended September 30, 2004 and 2005 from our unaudited consolidated financial statements includedelsewhere in this prospectus.

The financial data below should be read together with, and are qualified in their entirety by reference to, our historical consolidated combined financialstatements and the accompanying notes, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the historicalconsolidated financial statements and the accompanying notes of Spectrum and Elk City and its predecessor set forth elsewhere in this prospectus.

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Inceptionthrough

December31,

Years Ended December 31,

Nine Months Ended

September 30,

2000 2001 2002 2003 2004(1) 2004(1) 2005(2)

(dollars in thousands) (unaudited)Statement of income data:Revenue:Natural gas and liquids $ — $ — $ — $ — $ 72,109 $ 30,048 $ 218,268Transportation and compression 9,441 13,095 10,660 15,651 18,800 13,344 16,501Interest income and other 25 35 7 98 382 282 352

Total revenue and other income 9,466 13,130 10,667 15,749 91,291 43,674 235,121

Costs and Expenses:Natural gas and liquids — — — — 58,707 24,588 184,578Plant operating — — — — 2,032 931 7,242Transportation and compression 1,224 1,929 2,062 2,421 2,260 1,709 2,169General and administrative 603 1,114 1,482 1,662 4,642 2,901 9,127Depreciation and amortization 1,019 1,356 1,475 1,770 4,471 2,132 8,495Loss (gain) on arbritation settlement, net — — — — (1,457) 2,987 138Interest 9 176 250 258 2,301 1,202 8,478Minority interest in Atlas(3) 3,101 3,810 2,496 5,066 10,941 3,300 7,240

Total costs and expenses 5,956 8,385 7,765 11,177 83,897 39,750 227,467

Net income 3,510 4,745 2,902 4,572 7,394 3,924 7,654Premium on preferred unit redemption — — — — (400) (400) —

Net income attributable to owners $ 3,510 $ 4,745 $ 2,902 $ 4,572 $ 6,994 $ 3,524 $ 7,654

Balance sheet data (at period end):Property, plant and equipment, net $ 15,773 $ 20,009 $ 23,764 $ 29,628 $ 175,259 $ 172,312 $ 304,704Total assets 21,877 31,603 38,151 63,170 234,898 236,178 484,458Total debt, including current portion — 2,089 6,500 — 54,452 60,220 183,645Total owners’ equity (deficit) 3,510 8,255 11,157 15,729 21,405 15,325 (40,880)

Other financial data:Gross margin (4) $ 9,441 $ 13,095 $ 10,660 $ 15,651 $ 32,202 $ 18,804 $ 50,191EBITDA (5) 7,639 10,087 7,123 11,666 25,107 10,558 31,867Adjusted EBITDA (5) 7,639 10,087 7,123 11,666 24,350 13,887 34,814

Maintenance capital expenditures $ 138 $ 159 $ 170 $ 3,109 $ 1,516 $ 844 $ 1,110Expansion capital expenditures 1,192 1,569 5,060 4,526 8,527 3,575 33,409

Total capital expenditures $ 1,330 $ 1,728 $ 5,230 $ 7,635 $ 10,043 $ 4,419 $ 34,519

Operating data:Appalachia:Average throughput volumes (Mcf/d) 42,669 46,918 50,363 52,472 53,343 52,745 54,804Average transportation rate per Mcf $ 0.65 $ 0.76 $ 0.58 $ 0.82 $ 0.96 $ 0.92 $ 1.10Mid−Continent:Velma system:Gathered gas volume (Mcf/d) — — — — 56,441 55,580 69,091Processed gas volume (Mcf/d) — — — — 55,202 54,755 64,581Residue gas volume (Mcf/d) — — — — 42,659 41,555 52,471NGL production (Bbl/d) — — — — 5,799 5,916 6,812Condensate volume (Bbl/d) — — — — 185 204 269

Elk City system:Gathered gas volume (Mcf/d) — — — — — — 242,294Processed gas volume (Mcf/d) — — — — — — 116,688Residue gas volume (Mcf/d) — — — — — — 107,182NGL production (Bbl/d) — — — — — — 5,317Condensate volume (Bbl/d) — — — — — — 121

(1) Includes Atlas’ acquisition of Spectrum on July 16, 2004, representing five and one−half months’ operations for the year ended December 31, 2004 and twoand one−half months’ operations for the nine months ended September 30, 2004.

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(2) Includes Atlas’ acquisition of Elk City on April 14, 2005, representing five and one−half months’ operations for the nine months ended September 30, 2005.

(3) Represents the minority interest in the net income of Atlas.

(4) We define gross margin as revenue less purchased product costs. Purchased product costs include the cost of natural gas and NGLs that Atlas purchasesfrom third parties. Our management views gross margin as an important performance measure of core profitability of our operations and as a key componentof our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses. Thefollowing table reconciles our net income to gross margin (in thousands):

Inceptionthrough

December31,


Nine Months Ended

September 30,

2000 2001 2002 2003 2004 2004 2005

(unaudited)

Net income $ 3,510 $ 4,745 $ 2,902 $ 4,572 $ 7,394 $ 3,924 $ 7,654Plus (minus):Interest income and other (25) (35) (7) (98) (382) (282) (352)Plant operating — — — — 2,032 931 7,242Transportation and compression 1,224 1,929 2,062 2,421 2,260 1,709 2,169General and administrative 603 1,114 1,482 1,662 4,642 2,901 9,127Depreciation and amortization 1,019 1,356 1,475 1,770 4,471 2,132 8,495Loss (gain) on arbitration settlement, net — — — — (1,457) 2,987 138Interest 9 176 250 258 2,301 1,202 8,478Minority interest in Atlas 3,101 3,810 2,496 5,066 10,941 3,300 7,240

Gross margin $ 9,441 $ 13,095 $ 10,660 $ 15,651 $ 32,202 $ 18,804 $ 50,191

(5) EBITDA represents net income before net interest expense, income taxes, depreciation and amortization and minority interest in Atlas. Adjusted EBITDA iscalculated by adding to EBITDA other non−cash items such as compensation expenses associated with unit issuances to directors and employees. EBITDAand Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computingEBITDA may not be the same method used to compute similar measures reported by other companies. Adjusted EBITDA excludes net gain or loss onarbitration settlement as a non−recurring item. Adjusted EBITDA does not reflect approximately $1.0 million of additional general and administrativeexpense, we expect to incur in connection with our being a public company after this offering.

Certain items excluded from EBITDA are significant components in understanding and assessing an entity’s financial performance, such as their cost ofcapital and its tax structure, as well as historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDAbecause they provide investors and management with additional information as to Atlas’ ability to pay its fixed charges and are presented solely as asupplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cashflow as determined in accordance with generally accepted accounting principles or as indicators of Atlas’ operating performance or liquidity. The followingtable reconciles Adjusted EBITDA to EBITDA and EBITDA to our net income (in thousands):

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Inceptionthrough

December31,


Nine Months Ended

September 30,

2000 2001 2002 2003 2004 2004 2005

(unaudited)

Net income $ 3,510 $ 4,745 $ 2,902 $ 4,572 $ 7,394 $ 3,924 $ 7,654Plus:Minority interest in Atlas 3,101 3,810 2,496 5,066 10,941 3,300 7,240Interest expense 9 176 250 258 2,301 1,202 8,478Depreciation and amortization 1,019 1,356 1,475 1,770 4,471 2,132 8,495

EBITDA 7,639 10,087 7,123 11,666 25,107 10,558 31,867Adjustments:Non−cash compensation expense — — — — 700 342 2,809Loss (gain) on arbitration settlement, net — — — — (1,457) 2,987 138

Adjusted EBITDA $ 7,639 $ 10,087 $ 7,123 $ 11,666 $ 24,350 $ 13,887 $ 34,814

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our financial condition and results of operations in conjunction with the historical and pro forma financialstatements and notes thereto included elsewhere in this prospectus. For more detailed information regarding the basis of presentation for the followinginformation, you should read the notes to the historical and pro forma financial statements included elsewhere in this prospectus. In addition, you should read“Forward−Looking Statements” and “Risk Factors” for information regarding some of the risks inherent in our business.

Overview

Financial PresentationWe reflect our ownership interest in Atlas on a consolidated basis, which means that our financial results are combined with Atlas’ financial results. Thenon−controlling limited partner interests in Atlas will be reflected as an expense in our consolidated results of operations and as a liability on our consolidatedbalance sheet. We initially will have no separate operating activities apart from those conducted by Atlas, and our cash flows currently consist of distributionsfrom Atlas on our partnership interests in it, including the incentive distribution rights that we own. Our historical consolidated results of operations reflect theresults of operations of our wholly−owned subsidiary, Atlas Pipeline Partners GP, LLC, the general partner of Atlas. Throughout this discussion, when we referto “our” consolidated results of operations, we are referring to the results of consolidated operations of Atlas Pipeline GP. Atlas Pipeline GP’s consolidatedresults of operations principally reflect the results of operations of Atlas adjusted for non−controlling partners’ interest in Atlas’ net income. Accordingly, thediscussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations”reflects the operating activities and results of operations of Atlas. The historical results of our operations do not reflect the incremental expenses we expect toincur as a result of being a publicly traded partnership.

GeneralOur cash generating assets consist of our interests in Atlas, a publicly−traded Delaware limited partnership. Atlas is a midstream energy service provider engagedin the transmission, gathering and processing of natural gas in the Mid−Continent and Appalachian regions of the United States. Our interests in Atlas willinitially consist of a 100% ownership interest in Atlas Pipeline GP, the general partner of Atlas, which owns:


• all of the incentive distribution rights in Atlas, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed byAtlas as it reaches certain target distribution levels in excess of $0.42 per unit in any quarter; and

• 1,641,026 common limited partner units of Atlas, representing an approximate 12.8% limited partner interest.At Atlas’ current annual distribution rate of $3.32 per common unit, aggregate annual cash distributions to us on all our interests in Atlas would be approximately$20.0 million. The following table sets forth the historical Atlas distributions paid to its general partner, Atlas Pipeline GP, our wholly−owned subsidiary, duringthe periods indicated:

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Atlas Cash Distributions to Atlas Pipeline GP

Year Ended December31,

Twelve Months

2000 2001 2002 2003 2004

EndedSeptember30,

2005

(in thousands)Distributions on Atlas common units held by Atlas Pipeline GP $ 3,283 $ 4,103 $ 3,504 $ 3,914 $ 4,382 $ 5,005Distributions from ownership interest in the Atlas general partner 140 186 148 217 386 663Distributions from Atlas incentive distribution rights held by Atlas Pipeline GP 585 911 273 809 2,765 6,855

Total $ 4,008 $ 5,200 $ 3,925 $ 4,940 $ 7,533 $ 12,523


Atlas Pipeline Partners, L.P. is a publicly−traded Delaware limited partnership whose common units are listed on the New York Stock Exchange under thesymbol “APL.” Atlas Pipeline Partners, L.P.’s business activities are primarily conducted through, and its assets are owned by, its subsidiary Atlas PipelineOperating Partnership, L.P. and its subsidiaries, which are collectively referred to in this prospectus as Atlas.

Overview of Atlas’ OperationsThrough its Mid−Continent operations, which began in July 2004, Atlas owns and operates:

• a 75% interest in a FERC−regulated, 565−mile interstate pipeline system, that extends from southeastern Oklahoma through Arkansas and intosoutheastern Missouri and which has throughput capacity of approximately 322 MMcf/d;


• 1,765 miles of active natural gas gathering systems located in Oklahoma, Arkansas, northern Texas and the Texas panhandle, which transport gas fromwells and central delivery points in the Mid−Continent region to its natural gas processing plants or transmission lines.

Through its Appalachian operations, Atlas owns and operates 1,500 miles of active natural gas gathering systems located in eastern Ohio, western New York andwestern Pennsylvania. These systems gather natural gas from more than 5,120 wells for delivery to a variety of customers on major intra− and/or interstatepipeline systems and a limited number of direct end−users. Through an omnibus agreement and other agreements between Atlas and Atlas America, the parent ofAtlas and our general partner and a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin, Atlas gathers substantially all of thenatural gas for its Appalachian operations from wells operated by Atlas America. Among other things, the omnibus agreement requires Atlas America to connectto Atlas’ gathering systems wells Atlas America operates that are located within 2,500 feet of Atlas’ gathering systems. Atlas is also a party to natural gasgathering agreements with Atlas America under which it receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the naturalgas it transports. These agreements are continuing obligations and have no specified term except that they will terminate if Atlas’ general partner is removedwithout cause.

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Significant Acquisitions

Since Atlas’ initial public offering in January 2000 through December 2005, Atlas has completed five acquisitions at an aggregate cost of approximately $516.7million, including, most recently:

• In October 2005, Atlas acquired from Enogex, a wholly−owned subsidiary of OGE Energy Corp., all of the outstanding equity of Atlas Arkansas,which owns a 75% interest in NOARK, for $165.3 million, including estimated related transaction costs, plus $10.2 million for working capitaladjustments. NOARK’s principal assets include the Ozark Gas Transmission system, a 565−mile interstate natural gas pipeline, and Ozark GasGathering, a 365−mile natural gas gathering system. The remaining 25% interest in NOARK is owned by Southwestern.

• In April 2005, Atlas acquired all of the outstanding equity interests of Elk City for $196.0 million, including related transaction costs. Elk City’sprincipal assets include approximately 300 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle,a natural gas processing facility in Elk City, Oklahoma, with a total capacity of approximately 200 MMcf/d and a gas treatment facility in Prentiss,Oklahoma, with a total capacity of approximately 200 MMcf/d.

• In July 2004, Atlas acquired Spectrum for $141.6 million, including transaction costs and the payment of taxes due as a result of the transaction.Spectrum’s principal assets consist of 1,100 miles of active and 800 miles of inactive natural gas gathering pipelines in the Golden Trend area ofSouthern Oklahoma and the Barnett Shale area of North Texas and a natural gas processing facility in Stephens County, Oklahoma, with a totalcapacity of approximately 100 MMcf/d.

Contractual Revenue ArrangementsAtlas’ principal revenue is generated from the transportation and sale of residue gas and NGLs. Variables which affect Atlas’ revenue are:

• the volumes of natural gas gathered, transported and processed by Atlas which, in turn, depend upon the number of wells connected to its gatheringsystems, the amount of natural gas they produce, and the demand for natural gas and NGLs; and

• the transportation and processing fees paid to Atlas which, in turn, depend upon the price of the natural gas and NGLs it transports and processes,which itself is a function of the relevant supply and demand in the mid−continent, mid−Atlantic and northeastern areas of the United States.

In Appalachia, substantially all of the gas Atlas transports is for Atlas America under percentage of proceeds, or POP, contracts, as described below, where Atlasearns a fee equal to a percentage, generally 16%, of the selling price of the gas subject, in most cases, to a minimum of $0.35 or $0.40 per Mcf. Since Atlas’inception in January 2000, its Appalachian transportation fee has always exceeded this minimum. The balance of the Appalachian gas Atlas transports is forthird−party operators generally under fixed fee contracts.

Atlas’ revenue in the Mid−Continent region is determined primarily by the fees earned from the following types of arrangements:

Fee−Based Contracts. These contracts provide for a set fee for gathering and processing raw natural gas. Atlas’ revenue is a function of the volume of gasthat it gathers and processes and is not directly dependent on the value of the natural gas.

POP Contracts. These contracts provide for Atlas to retain a negotiated percentage of the sale proceeds from residue natural gas and NGLs it gathers andprocesses, with the remainder being remitted to the producer. In this situation, Atlas and the producer are directly dependent on the volume of thecommodity and its value; Atlas owns a percentage of that commodity and is directly subject to its market value.

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Keep−Whole Contracts. These contracts require Atlas, as the processor, to bear the economic risk (the “processing margin risk”) that the aggregate proceedsfrom the sale of the processed natural gas and NGLs could be less than the amount that the processor paid for the unprocessed natural gas. However, sincethe gas received by the Elk City system, which is currently Atlas’ only gathering system with keep−whole contracts, is generally low in liquids content andmeets downstream pipeline specifications without being processed, the gas can be bypassed around the Elk City processing plant and delivered directly intodownstream pipelines during periods of margin risk. Therefore, the processing margin risk associated with such type of contracts is minimized.

As a result of Atlas’ POP and keep whole contracts, Atlas’ results of operations and financial condition substantially depend upon the price of natural gas andNGLs. Atlas believes that future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of UnitedStates economic growth. Based on historical trends, Atlas generally expects NGL prices to follow changes in crude oil prices over the long term, which itbelieves will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the worldeconomy. The number of active oil and gas rigs has increased in recent years, mainly due to recent significant increases in natural gas prices, which could resultin sustained increases in drilling activity during the current and future periods. However, energy market uncertainty could negatively impact North Americandrilling activity in the short term. Lower drilling levels over a sustained period would have a negative effect on natural gas volumes gathered and processed.

Atlas closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodityinstruments such as natural gas, crude oil and NGL contracts to hedge a portion of the value of its assets and operations from such price risks. Atlas does notrealize the full impact of commodity price changes because some of its sales volumes were previously hedged at prices different than actual market prices.

Results of Our OperationsThe results of operations discussed below principally reflect the activities of Atlas on and after January 1, 2002. Because our financial statements representconsolidated results of Atlas, our financial statements are substantially similar to Atlas’. The primary differences in our financial statements include the followingadjustments:

• Interest of non−controlling limited partners in Atlas’ net income and partners’ capital. We adjust our net income by excluding the income allocated toAtlas limited partner units that are not directly or indirectly owned by us. This allocation of Atlas’ income to non−controlling limited partners isreflected as minority interest expense in our consolidated statements of income. At the time of completion of the offering, we will own a 12.8% limitedpartner interest in Atlas and the non−affiliated unitholders will own a 85.2% limited partner interest. Our consolidated balance sheet includes a minorityinterest liability which reflects the proportion of Atlas owned by its partners other than us.

• Our general and administrative expenses. We incur general and administrative expenses that are independent from Atlas’ operations and are notreflected on Atlas’ consolidated financial statements.

Nine Months Ended September30, 2004 Compared to Nine Months Ended September30, 2005Revenue. Natural gas and liquids revenue was $218.3 million for the nine months ended September 30, 2005, an increase of $188.3 million from $30.0 millionfor the first nine months of 2004. The increase was primarily attributable to contributions from the Elk City system, acquired in April 2005, and the Velmasystem, acquired in July 2004, and an increase in commodity prices between periods. Gross natural gas gathered averaged 69.1 MMcf/d on the Velma system forthe first nine months of 2005, an increase of 24% from the first nine months of 2004. Gross natural gas gathered on the Elk City system averaged 242.3 MMcf/dfrom its date of acquisition through September 30, 2005.

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Appalachia transportation and compression revenue increased to $16.5 million for the nine months ended September 30, 2005 from $13.3 million for the firstnine months of 2004. This $3.2 million increase was primarily due to an increase in the average transportation rate earned and an increase in the volumes ofnatural gas Atlas transported. Atlas’ average transportation rate was $1.10 per Mcf for the nine months ended September 30, 2005 as compared to $0.92 per Mcffor the prior year comparable period, an increase of $0.18 per Mcf. Appalachia’s average throughput volumes were 54.8 MMcf/d for the first nine months of2005 as compared with 52.7 MMcf/d for the prior year comparable period, an increase of 2.1 MMcf/d. The increase in the average daily throughput volume wasprincipally due to new wells connected to Atlas’ gathering system and the completion of a capacity expansion project on certain sections of its pipeline systemduring the current period.

Costs and Expenses. Natural gas and liquids cost of goods sold of $184.6 million and plant operating expenses of $7.2 million for the nine months endedSeptember 30, 2005 represented increases of $160.0 million and $6.3 million, respectively, from the prior year’s comparable period amounts due primarily tocontributions from the acquisitions and an increase in commodity prices. Appalachia transportation and compression expenses increased $0.5 million to $2.2million for the first nine months of 2005 due mainly to higher operating costs as a result of compressors added in connection with Atlas’ capacity expansionproject and higher maintenance expense as a result of additional wells connected to the pipeline.

General and administrative expenses, including amounts reimbursed to affiliates, increased $6.2 million to $9.1 million for the nine months ended September 30,2005 compared with $2.9 million for the prior year comparable period. This increase was mainly due to a $2.6 million increase in non−cash compensationexpense related to phantom units issued under Atlas’ long−term incentive plan and $3.7 million of expenses associated with the acquisitions. Depreciation andamortization increased to $8.5 million for the nine months ended September 30, 2005 compared with $2.1 million for the first nine months of 2004 dueprincipally to the increased asset base associated with the acquisitions.

Interest expense increased to $8.5 million for the nine months ended September 30, 2005 as compared with $1.2 million for the prior year comparable period.This $7.3 million increase was primarily due to interest associated with borrowings under Atlas’ credit facility to finance the acquired assets and $1.0 million ofaccelerated amortization of deferred financing costs. This accelerated amortization was associated with the retirement of the term portion of Atlas’ $270 millioncredit facility in April 2005. For the third quarter of 2004, Atlas incurred $3.0 million of costs in connection with the terminated attempt to acquire AlaskaPipeline Company and subsequent legal action. Atlas settled the matter in the fourth quarter 2004 and received $5.5 million.

Minority interest in Atlas net income, which represents the allocation of Atlas earnings to its non−affiliated limited partners, increased to $7.2 million for thenine months ended September 30, 2005 as compared with $3.3 million for the prior year comparable period. This $3.9 million increase was primarily due to anincrease in Atlas’ overall net income and an increase in the number of its outstanding limited partner units due to additional equity offerings in April 2004, July2004 and June 2005.

Year Ended December31, 2003 Compared to Year Ended December31, 2004Revenue. Natural gas and liquids revenue of $72.1 million for the year ended December 31, 2004 was associated with the acquisition of Atlas’ Velma operationsin July 2004 and reflect approximately five and one half months of operations at Velma in 2004. Appalachia transportation and compression revenue increased to$18.8 million for the year ended December 31, 2004 from $15.7 million for the prior year. This $3.1 million increase was primarily due to an increase in theaverage transportation rate earned and an increase in the volumes of natural gas transported. The average transportation rate was $0.96 per Mcf for the year endedDecember 31, 2004 as compared with $0.82 per Mcf for the prior year, an increase of $0.14 per Mcf. The average daily throughput volumes were 53.3 MMcf/dfor the year ended December 31, 2004 as compared with 52.5 MMcf/d for the prior year, an increase of 0.8 MMcf/d. The increase in the average daily throughputvolume was principally due to new wells connected to the Appalachia gathering system, partially offset by the natural decline in production volumes fromexisting wells connected to it.

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Costs and Expenses. Natural gas and liquids cost of goods sold of $58.7 million and plant operating expenses of $2.0 million for the year ended December 31,2004 were associated with the acquisition of Atlas’ Velma operations and reflect five and one half months of activity at Velma. Appalachian transportation andcompression expenses decreased slightly to $2.3 million for the year ended December 31, 2004 as compared with $2.4 million for the prior year. This decreasewas primarily due to a decrease in compressor expenses due to the purchase of several compressors that were previously leased at the end of 2003.

General and administrative expenses, including amounts reimbursed to affiliates, increased $3.0 million to $4.6 million for the year ended December 31, 2004compared with $1.6 million for the prior year. This increase was mainly due to $1.1 million of general and administrative expenses associated with Atlas’ Velmaoperations, $0.8 million of expenses related to non−cash compensation expense for phantom units issued under our long−term incentive plan, a $0.5 millionincrease in allocations of compensation and benefits from Atlas America and its affiliates due to management time associated with acquisitions and publicofferings, and $0.3 million of costs associated with the implementation of Sarbanes−Oxley and the preparation and filing of two tax returns for 2003. The filingof two tax returns was a result of our percentage interest in Atlas being reduced below 50% as a result of Atlas’ offering of common units in May 2003, requiringa change in its tax year−end from September 30 to December 31. This necessitated the filing of an additional short year tax return. This expense isnon−recurring.

Depreciation and amortization increased to $4.5 million for the year ended December 31, 2004 compared with $1.8 million for the prior year due principally tothe increased asset base associated with the acquisition of the Velma operations and pipeline extensions and compressor upgrades in Appalachia.

Net gain on arbitration settlement of $1.5 million for the year ended December 31, 2004 is the result of a December 30, 2004 settlement agreement with SEMCOsettling all issues and matters related to the terminated acquisition of Alaska Pipeline Company by Atlas from SEMCO. The gain reflects $5.5 million receivedfrom SEMCO, net of $4.0 million of associated costs.

Interest expense increased to $2.3 million for the year ended December 31, 2004 as compared with $0.3 million for the prior year. This $2.0 million increase wasprimarily due to interest associated with borrowings under the credit facility to finance the acquisition of the Velma operations.

Minority interest in Atlas net income increased to $10.9 million for the year ended December 31, 2004 as compared with $5.1 million for the prior year. This$5.8 million increase was primarily due to an increase in Atlas’ overall net income and an increase in the number of outstanding limited partner units due toadditional equity offerings in May 2003, April 2004 and July 2004.

Year Ended December31, 2002 Compared with Year Ended December31, 2003Revenue. Appalachian transportation and compression revenue increased to $15.7 million for the year ended December 31, 2003 from $10.7 million for the prioryear. This $5.0 million increase was primarily due to an increase in the average transportation rate earned and an increase in the volumes of natural gastransported. The average transportation rate was $0.82 per Mcf for the year ended December 31, 2003 as compared with $0.58 per Mcf for the prior year, anincrease of $0.24 per Mcf. Average daily throughput volumes were 52.5 MMcf/d for the year ended December 31, 2003 as compared with 50.4 MMcf/d for theprior year, an increase of 2.1 MMcf/d. The increase in the average daily throughput volume was principally due to new wells connected to the Appalachiangathering system, partially offset by the natural decline in production volumes from existing wells connected to the system.

Costs and Expenses. Transportation and compression expenses increased to $2.4 million for the year ended December 31, 2003 as compared with $2.1 millionfor the prior year. This increase was primarily due to an increase in compressor expenses due to additional compressors and higher lease rates for thesecompressors.

General and administrative expenses, including amounts reimbursed to affiliates, increased $0.2 million to $1.7 million for the year ended December 31, 2003compared with $1.5 million for the prior year. This increase was mainly due to a $0.6 million increase in allocations of compensation and benefits from Atlas

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America and its affiliates due to management time associated with potential acquisitions and public offerings, partially offset by a decline in professional feesassociated with potential acquisitions and public offerings.

Depreciation and amortization increased to $1.8 million for the year ended December 31, 2003 compared with $1.5 million for the prior year due principally tothe increased asset base associated with pipeline extensions and compressor upgrades and purchases.

Minority interest in Atlas net income increased to $5.1 million for the year ended December 31, 2003 as compared with $2.5 million for the prior year. This $2.6million increase was primarily due to an increase in Atlas’ overall net income and an increase in the number of outstanding limited partner units due to anadditional equity offering in May 2003.

Liquidity and Capital Resources

GeneralAtlas’ primary sources of liquidity are cash generated from operations and borrowings under its credit facility. Atlas’ primary cash requirements, in addition tonormal operating expenses, are for debt service, capital expenditures and quarterly distributions to its unitholders and us, as general partner. In general, Atlasexpects to fund:

• cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

• expansion capital expenditures and working capital deficits through the retention of cash and additional borrowings; and

• debt principal payments through additional borrowings as they become due or by the issuance of additional common units.At September 30, 2005, Atlas had $183.5 million of outstanding borrowings under its credit facility and $7.7 million of outstanding letters of credit which are notreflected as borrowings on our consolidated balance sheet, with $33.8 million of available borrowing capacity. In addition to the availability under the creditfacility, Atlas has a universal shelf registration statement on file with the Securities and Exchange Commission, which allows it to issue equity or debt securities,See “—Atlas’ Shelf Registration Statement.” At September 30, 2005, we had a working capital deficit of $9.6 million compared with working capital of $27.9million at December 31, 2004. This decrease was primarily due to the settlement of accounts receivable from affiliates and an increase in the current portion ofAtlas’ net hedge liability between periods and is reflected in the change in fair−market value of its derivative instruments based on the subsequent increases inthe price of natural gas after Atlas entered into the hedges. These price increases will be reflected in our consolidated statements of income when the contractssettle.

Cash FlowsNine Months Ended September30, 2004 Compared with Nine Months Ended September30, 2005. Net cash provided by operating activities of $31.0 millionfor the nine months ended September 30, 2005 increased $21.5 million from $9.5 million for the first nine months of 2004. The increase is derived principallyfrom increases in cash provided by working capital of $13.4 million, net income of $4.1 million, minority interest in Atlas’ net income of $3.9 million,depreciation and amortization of $6.4 million, and non−cash compensation expense of $2.5 million, partially offset by a $8.6 million increase in cashdistributions to Atlas’ minority interest partners. The increase in cash provided by working capital between periods is mainly due to timing of settlement ofaccounts receivable due from affiliates. The increases in net income, minority interest and depreciation and amortization were principally due to the contributionfrom the acquisitions of Spectrum in July 2004 and Elk City in April 2005. The increase in cash distributions to Atlas minority interest partners was due to anincrease in their limited partner units outstanding and the distribution amount per limited partner unit.

Net cash used in investing activities was $229.9 million for the nine months ended September 30, 2005, an increase of $84.2 million from $145.7 million for thefirst nine months of 2004. This increase was

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principally due to the acquisitions mentioned previously and a $30.1 million increase in capital expenditures. See further discussion of capital expenditures under“— Capital Requirements.”

Net cash provided by financing activities was $192.7 million for the nine months ended September 30, 2005, an increase of $42.5 million from $150.2 million forthe first nine months of 2004. This increase was principally due to a $69.3 million increase in net borrowings under Atlas’ credit facility, mainly to fund theacquisition of the Elk City assets, partially offset by the distribution to owners.

Year Ended December31, 2003 Compared with Year Ended December31, 2004. Net cash provided by operating activities of $11.3 million for the year endedDecember 31, 2004 increased $6.7 million from $4.6 million for the prior year. The increase is derived principally from increases in net income of $2.4 million,minority interest in Atlas net income of $5.9 million, depreciation and amortization of $2.7 million, and non−cash compensation expense of $0.7 million,partially offset by an increase in cash distributions to Atlas minority interest partners of $4.4 million. The increases in net income, minority interest anddepreciation and amortization were principally due to the acquisition of the Velma operations in July 2004. The increase in cash distributions to Atlas minorityinterest partners was due to an increase in its limited partner units outstanding and its distribution amount per limited partner unit.

Net cash used in investing activities was $151.8 million for the year ended December 31, 2004, an increase of $142.6 million from $9.2 million for the prior year.This increase was principally due to the acquisition of the Velma operations in July 2004 and a $2.4 million increase in capital expenditures. See furtherdiscussion of capital expenditures under “—Capital Requirements.”

Net cash provided by financing activities was $143.6 million for the year ended December 31, 2004, an increase of $125.9 million from $17.7 million for theprior year. This increase was principally due to $67.9 million of additional net proceeds received from Atlas’ sales of its common units and $60.7 million of netborrowings under its credit facility, mainly to fund the acquisition of the Velma operations.

Year Ended December31, 2002 Compared with Year Ended December31, 2003. Net cash provided by operating activities of $4.6 million for the year endedDecember 31, 2003 increased $4.0 million from $0.6 million for the prior year. The increase is derived principally from increases in net income of $1.7 million,minority interest in Atlas net income of $2.6 million, and an increase in cash provided by working capital of $1.0 million, partially offset by an increase in cashdistributions to Atlas minority interest partners of $1.5 million. The increases in net income and minority interest were principally due to an increase in theAppalachian average transportation rate. The increase in cash distributions to Atlas minority interest partners was due to an increase in its limited partner unitsoutstanding and its distribution amount per limited partner unit.

Net cash used in investing activities was $9.2 million for the year ended December 31, 2003, an increase of $4.0 million from $5.2 million for the prior year. Thisincrease was principally due to a $2.4 million increase in capital expenditures and $1.5 million of deferred costs associated with pending acquisitions. See furtherdiscussion of capital expenditures under “—Capital Requirements.”

Net cash provided by financing activities was $17.7 million for the year ended December 31, 2003, an increase of $13.4 million from $4.3 million for the prioryear. This increase was principally due to $25.2 million of net proceeds received from Atlas’ sale of common units, partially offset by $10.9 million of netreductions of outstanding borrowings under Atlas’ credit facility.

Capital RequirementsAtlas’ operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmentalregulations. The capital requirements for Atlas’ operations consist primarily of:

• maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

• expansion capital expenditures to acquire complementary assets and to expand the capacity of Atlas’ existing operations.

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The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (inthousands):

Years Ended December31,Nine Months Ended

September30,

2002 2003 2004 2004 2005

Maintenance capital expenditures $ 170 $ 3,109 $ 1,516 $ 844 $ 1,110Expansion capital expenditures 5,060 4,526 8,527 3,575 33,409

Total capital expenditures $ 5,230 $ 7,635 $10,043 $ 4,419 $34,519

Expansion capital expenditures increased to $33.4 million for the nine months ended September 30, 2005, due principally to expansions of the Velma and ElkCity gathering systems and processing facilities to accommodate new wells drilled in Atlas’ service areas. In addition, expansion capital expenditures increaseddue to compressor upgrades and gathering system expansions in the Appalachian region. Maintenance capital expenditures for the nine months endedSeptember 30, 2005 remained relatively consistent compared with the prior year period. As of September 30, 2005, Atlas is committed to expend approximately$36.6 million on pipeline extensions, compressor station upgrades and processing facility upgrades, including $13.1 million related to the Sweetwater gas plant.We anticipate that Atlas’ expansion capital expenditures will continue to increase in the fourth quarter of 2005 compared with the prior year period as a result ofan increase in the estimated number of well connections to Atlas’ gathering systems.

Expansion capital expenditures were $8.5 million for the year ended December 31, 2004, an increase of $4.0 million compared with $4.5 million for the prioryear due principally to expansions of the Velma gathering system and processing facilities to accommodate new wells drilled in Atlas’ service areas andcompressor upgrades and gathering system expansions in the Appalachian region. Maintenance capital expenditures were $1.5 million for the year endedDecember 31, 2004, a decrease of $1.6 million compared with $3.1 million for the prior year due principally to the purchase of Appalachian pipelinecompressors in 2003 to replace units which were formerly leased.

Expansion capital expenditures declined slightly to $4.5 million for the year ended December 31, 2003 due to the timing of expenditures for well connections,compressor upgrades, and gathering system expansions in the Appalachian region. Maintenance capital expenditures were $3.1 million for the year endedDecember 31, 2003, an increase of $2.9 million compared with the prior year due principally to the purchase of Appalachian pipeline compressors in 2003 toreplace units which were formerly leased.

Atlas Partnership DistributionsAtlas’ partnership agreement requires that Atlas distribute 100% of available cash to its partners within 45 days following the end of each calendar quarter inaccordance with their respective percentage interests. Available cash consists generally of all of Atlas’ cash receipts, less cash disbursements and net additions toreserves, including any reserves required under debt instruments for future principal and interest payments.

Atlas Pipeline GP, as general partner, is granted discretion by Atlas’ partnership agreement to establish, maintain and adjust reserves for future operatingexpenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude,but only by type of future cash requirements with which they can be associated. When Atlas Pipeline GP determines Atlas’ quarterly distributions, it considerscurrent and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to Atlas’ limited partners and 2.0% to its general partner. These distribution percentages are modified to provide forincentive distributions to be paid to Atlas Pipeline GP if quarterly distributions to limited partners exceed specified targets. Incentive distributions are generallydefined as all cash distributions paid to its general partner that are in excess of 2.0% of the aggregate amount of cash being distributed. Incentive distributionsdeclared were $2.8 million and $5.7 million for the year ended December 31, 2004 and for the nine months ended September 30, 2005, respectively.

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Contractual Obligations and Commercial Commitments

The following tables summarizes Atlas’ contractual obligations and commercial commitments at September 30, 2005 (in thousands):

Payments due by period

Contractual cash obligations:Total Less than 1 year 1 − 3 Years 4 − 5 Years

After 5years

Long−term debt (1) $ 183,645 $ 63 $ 82 $ 183,500 $ —Operating leases 3,663 1,948 1,427 288 —

Total contractual cash obligations $ 187,308 $ 2,011 $ 1,509 $ 183,788 $ —

(1) Not included in the table above are estimated interest payments calculated at the rates in effect at September 30, 2005: 2006 – $12.3 million; 2007 – $12.3million; 2008 – $12.3 million; 2009 – $12.3 million; and 2010 – $6.6 million.

The operating leases represent lease commitments for compressors, office space, and office equipment with varying expiration dates. These commitments areroutine and were made in the normal course of Atlas’ business.

Amount of commitment expiration per period

Other commercial commitments:Total Less than 1 year 1 – 3 Years 4 – 5 Years

After 5years

Standby letters of credit $ 7,692 $ 7,667 $ 25 $ — $ —Other commercial commitments 36,642 36,642 — — —

Total commercial commitments $44,334 $ 44,309 $ 25 $ — $ —

Other commercial commitments relate to commitments to install new compressors and sales lines for new well hookups, and expenditures for pipelineextensions.

Atlas’ Equity OfferingsOn November 28, 2005, Atlas sold 2,700,000 of its common units in a public offering for gross proceeds of $113.4 million. In addition, pursuant to an optiongranted to the underwriters of the offering, Atlas sold 330,000 common units on December 27, 2005 for gross proceeds of $13.9 million, or aggregate total grossproceeds of $127.3 million including the November 2005 offering. The sale of the units resulted in net proceeds of approximately $120.9 million, after estimatedunderwriting commissions and other transaction costs. Atlas primarily utilized the net proceeds from the sale to repay a portion of the amounts due under itscredit facility. Subsequent to this equity offering, Atlas Pipeline GP’s ownership interest in Atlas was 14.8%, including its 2.0% general partner interest.

In June 2005, Atlas sold 2,300,000 common units in a public offering for total gross proceeds of $96.5 million. The units were issued under Atlas’ previouslyfiled shelf registration statement. The sale of the common units resulted in net proceeds of approximately $91.7 million, after underwriting commissions andother transaction costs. Atlas primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its credit facility.

In July 2004, Atlas sold 2,100,000 common units in a public offering for total gross proceeds of $73.0 million. The units were issued under Atlas’ Form S−3shelf registration statement. The sale of the common units resulted in net proceeds of approximately $67.5 million, after underwriting commissions and othertransaction costs. Atlas utilized the net proceeds from the sale primarily to repay a portion of the amounts due under its credit facility and to redeem preferredunits issued in connection with the acquisition of Spectrum Field Services, Inc. in July 2004 for $20.4 million.

In April 2004, Atlas sold 750,000 common units in a public offering for total gross proceeds of $27.0 million. The units were issued under Atlas’ shelfregistration statement. The sale of the common units resulted in net proceeds of approximately $25.2 million, after underwriting commissions and othertransaction

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costs. Atlas utilized the net proceeds from the sale primarily to repay a portion of the amounts due under its credit facility.

In May 2003, Atlas sold 1,092,500 common units in a public offering for total gross proceeds of $27.3 million. The units were issued under Atlas’ shelfregistration statement. The sale of the units resulted in net proceeds of approximately $25.2 million, after underwriting commissions and other transaction costs.Atlas utilized the net proceeds from the sale primarily to repay a portion of the amounts due under its credit facility.

Atlas’ Shelf Registration StatementAtlas has an effective shelf registration statement with the Securities and Exchange Commission that permits it to periodically issue equity and debt securities fora total value of up to $500 million. On November 28, 2005, Atlas sold 2,700,000 of its common units in a public offering for gross proceeds of $113.4 million. Inaddition, pursuant to an option granted to the underwriters of the offering, Atlas sold 330,000 common units on December 27, 2005 for gross proceeds of $13.9million, or aggregate total gross proceeds of $127.3 million including the November 2005 offering. The sale of the units resulted in net proceeds ofapproximately $120.9 million, after estimated underwriting commissions and other transaction costs. Atlas primarily utilized the net proceeds from the sale torepay a portion of the amounts due under its credit facility. Subsequent to this equity offering, Atlas Pipeline GP’s ownership interest in Atlas was 14.8%,including its 2.0% general partner interest. As of December 31, 2005, $372.7 million remains available for issuance under the shelf registration statement.However, the amount, type and timing of any offerings will depend upon, among other things, the funding requirements of Atlas, prevailing market conditions,and compliance with Atlas’ credit facility covenants.

Atlas’ Credit FacilityIn April 2005, Atlas entered into a new $270.0 million credit facility with a syndicate of banks, which replaced its existing $135.0 million facility. The facilitywas comprised of a five−year $225.0 million revolving line of credit and a five−year $45.0 million term loan. The term loan portion of the credit facility wasrepaid and retired from the net proceeds of the June 2005 equity offering. The revolving portion of the credit facility bears interest, at Atlas’ option, at either (i)Adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5% or the Wachovia Bank prime rate (each plus theapplicable margin). The weighted average interest rate on the outstanding credit facility borrowings at December 31, 2004 and September 30, 2005 was 7.0% and6.6%, respectively. Up to $10.0 million of the credit facility may be utilized for letters of credit, of which $2.2 million and $7.7 million was outstanding atDecember 31, 2004 and September 30, 2005, respectively. These outstanding letter of credit amounts were not reflected as borrowings on our consolidatedbalance sheet. Borrowings under the credit facility are secured by a lien on and security interest in all of Atlas’ property and that of its subsidiaries, and by theguaranty of each of Atlas’ subsidiaries. The credit facility contains customary covenants, including restrictions on Atlas’ ability to incur additional indebtedness;make certain acquisitions, loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets,including the sale or transfer of interests in its subsidiaries.

The events which constitute an event of default are also customary for loans of this size, including payment defaults, breaches of representations or covenantscontained in the credit agreements, adverse judgments against Atlas in excess of a specified amount, and a change of control of Atlas’ general partner.

The credit facility requires Atlas to maintain a ratio of senior secured debt (as defined in the credit facility) to EBITDA (as defined in the credit facility) of notmore than 6.0 to 1.0, reducing to 5.75 to 1.0 on March 31, 2006, 4.5 to 1.0 on June 30, 2006, and 4.0 to 1.0 on September 30, 2006; a funded debt (as defined inthe credit facility) to EBITDA ratio of not more than 6.0 to 1.0, reducing to 5.75 to 1.0 on March 31, 2006 and to 4.5 to 1.0 on June 30, 2006; and an interestcoverage ratio (as defined in the credit facility) of not less than 2.5 to 1.0, increasing to 3.0 to 1.0 on March 31, 2006. The credit facility defines EBITDA toinclude pro forma adjustments, acceptable to the administrator of the facility, following material acquisitions. The definition of EBITDA contained in the creditfacility is substantially similar to the definition of Adjusted

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EBITDA used in this prospectus, except that: (1) the credit facility definition of EBITDA includes net gain or loss on arbitration settlement, while the definitionof Adjusted EBITDA excludes net gain or loss on arbitration settlement as a non−recurring item, and (2) the credit facility definition of EBITDA includesEBITDA of NOARK only to the extent of cash distributions from NOARK, while the definition of Adjusted EBITDA includes Atlas’ percentage interest inNOARK’s EBITDA. The ratios described above include only the operations of Atlas and its subsidiaries, and exclude our operations and those of oursubsidiaries that are not subsidiaries of Atlas. As of September 30, 2005, pro forma for the acquisition of NOARK, Atlas’ ratio of senior secured debt to EBITDAwas 5.4 to 1.0, its funded debt ratio was 5.4 to 1.0 and its interest coverage ratio was 2.8 to 1.0

Atlas is unable to borrow under its credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “workingcapital borrowings” pursuant to its partnership agreement. Because Atlas will be unable to borrow money to pay distributions unless it establishes a facility thatmeets the definition contained in its partnership agreement, Atlas’ ability to pay a distribution in any quarter is solely dependent on its ability to generatesufficient operating surplus with respect to that quarter.

NOARK NotesAs of November 30, 2005, NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., had outstanding $66.0 million in principal amount of 7.15% notes due in2018. The notes are governed by an indenture dated June 1, 1998 for which UMB Bank, N.A. serves as trustee. Interest on the notes is payable semi−annually, incash, in arrears on June 1 and December 1 of each year. Liability under the notes was allocated severally 40% to Atlas Arkansas, as successor to Enogex, and60% to Southwestern, and the parties are several guarantors for their respective allocations.

The notes are subject to a semi−annual redemption in installments of $1.0 million each at a redemption price of 100% of the principal, plus accrued and unpaidinterest. Additionally, at the option of either Enogex or Southwestern, notes in an aggregate principal amount guaranteed by either company as of a particularpayment date may be redeemed at such notes’ redemption price plus a make−whole premium and unpaid interest accrued to that date by giving the trustee at least60 days notice. As part of the NOARK acquisition, Enogex agreed to redeem its portion of the notes as promptly as practicable after the closing, and at theclosing it deposited cash sufficient to redeem the notes into an escrow account. The redemption of $26.4 million of the notes was completed on December 5,2005. After the redemption, $39.6 million of notes remain outstanding, for which Southwestern remains liable. Under the partnership agreement, payments on thenotes will be made from amounts otherwise distributable to Southwestern and, if that amount is insufficient, Southwestern is required to make a capitalcontribution to NOARK. NOARK distributes cash available for distribution to the partners, after amounts payable on their respective allocations of the notes, inaccordance with their percentage interests.

Significant Announced Internal Growth ProjectOn October 19, 2005, Atlas announced plans to complete construction of a new natural gas processing plant in Beckham County, Oklahoma near its Prentisstreating facility, in the third quarter of 2006. The new plant, to be known as the Sweetwater gas plant, will be scaled to 120 MMcf/d of processing capacity. TheSweetwater gas plant will be located west of Atlas’ Elk City gas plant, and is being built to further access natural gas production actively being developed inwestern Oklahoma and the Texas panhandle. Along with the Sweetwater gas plant, Atlas will construct a gathering system to be located primarily in westernOklahoma and in the Texas panhandle, more specifically, Beckham and Roger Mills counties in Oklahoma and Hemphill County, Texas. Atlas anticipates thatconstruction of the Sweetwater gas plant and associated gathering system will cost approximately $40.0 million and will generate cash flow of $8.0 million to$10.0 million annually.

Environmental RegulationAtlas’ operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the release of regulated materialsinto the environment or otherwise relating to

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environmental protection or human health or safety. We believe that Atlas’ operations and facilities are in substantial compliance with applicable environmentallaws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, theimposition of remedial requirements, and the issuance of injunctions limiting or preventing some or all of our operations. Atlas has an ongoing environmentalcompliance program. However, risks of accidental leaks or spills are associated with the transportation of natural gas. There can be no assurance that Atlas willnot incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation ofits business. Moreover, it is possible that other developments, such as increasingly strict environmental laws and regulations and enforcement policies hereunder,could result in increased costs and liabilities to Atlas.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that there will be continuing changes. Onetrend in environmental regulation is to increase reporting obligations and place more restrictions and limitations on activities, such as emissions of pollutants,generation and disposal of wastes and use, storage and handling of chemical substances, that may impact human health, the environment and/or endangeredspecies. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for Atlas and other similar businesses throughoutthe United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. Atlas will attempt to anticipatefuture regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that Atlas will identify and properly anticipate eachsuch charge, or that its efforts will prevent material costs, if any, from arising.

Inflation and Changes in PricesInflation affects the operating expenses of Atlas’ gathering systems. Increases in those expenses are not necessarily offset by increases in transportation fees thatthe gathering operations are able to charge. While we anticipate that inflation will affect Atlas’ future operating costs, we can not predict the timing or amountsof any such effects. In addition, the value of Atlas’ gathering systems has been and will continue to be affected by changes in natural gas prices. Natural gasprices are subject to fluctuations which we are unable to control or accurately predict.

Critical Accounting Policies and EstimatesThe preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires making estimatesand assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statementsand the reported amounts of actual revenue and expenses during the reporting period. Although we and Atlas believe our estimates are reasonable, actual resultscould differ from those estimates. Changes in these estimates could materially affect our and Atlas’ financial position, results of operations or cash flows. Keyestimates used by Atlas’ management include estimates used to record revenue and expense accruals, depreciation and amortization, asset impairment and fairvalues of assets acquired. We summarize our and Atlas’ significant accounting policies in our consolidated financial statements included in this prospectus. Thecritical accounting policies that we have identified are discussed below.

Use of EstimatesThe preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States requires managementto make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the dateof our consolidated financial statements, as well as the reported amounts of revenue and expense during the reporting periods. Actual results could differ fromthose estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery.Consequently, our most current month’s financial results include estimated volumes and market prices. Differences between estimated and actual amounts arerecognized in the following month’s financial results. We believe that the operating results presented for the year ended

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December 31, 2004 and the nine months ended September 30, 2005 represent actual results in all material respects (see Revenue Recognition accounting policyfor further description).

Receivables

In evaluating the realizability of accounts receivable, Atlas performs ongoing credit evaluations of its customers and adjusts credit limits based upon paymenthistory and the customer’s current creditworthiness, as determined by its review of the customers’ credit information. Atlas extends credit on an unsecured basisto many of its energy customers. At December 31, 2004 and September 30, 2005, no allowance was recorded for uncollectible accounts receivable impairment.

Revenue RecognitionRevenue in the Appalachian segment is recognized at the time the natural gas is transported through the gathering systems. Under the terms of its natural gasgathering agreements with Atlas America and its affiliates, Atlas receives fees for gathering natural gas from wells owned by Atlas America, by drillinginvestment partnerships sponsored by Atlas America or by independent third parties. The fees received for the gathering services are generally the greater of 16%of the gross sales price for gas produced from the wells, or $0.35 or $0.40 per Mcf, depending on the ownership of the well. Substantially all gas gatheringrevenue is derived under this agreement. Fees for transportation services provided to independent third parties whose wells are connected to Atlas’s Appalachiangathering systems are at separately negotiated prices.

Revenue in the Mid−Continent segment is recognized at the time the natural gas is processed and the resulting residue gas and NGLs are sold. The majority ofthis revenue is based on POP and fixed−fee contracts. Under its POP purchasing arrangements, Atlas purchases natural gas at the wellhead, processes the naturalgas by extracting NGLs and removing impurities and sells the residue gas and NGLs at market−based prices, remitting to producers a contractually−determinedpercentage of the sale proceeds.

Atlas accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs and oil and the receipt of a delivery statement. This revenueis recorded based upon volumetric data from its records and management estimates of the related transportation and compression fees which are, in turn, basedupon applicable product prices (see Use of Estimates accounting policy for further description). Atlas had unbilled revenue at December 31, 2004 andSeptember 30, 2005 of $15.3 million and $42.1 million, respectively, included in accounts receivable and accounts receivable−affiliates within our consolidatedbalance sheets.

Intangible AssetsAt September 30, 2005, Atlas had $12.4 million of intangible assets, net of accumulated amortization of $0.5 million, which was recorded in connection withnatural gas gathering contracts assumed in consummated acquisitions. Statement of Financial Accounting Standards No. 142, “Goodwill and Other IntangibleAssets,” (“SFAS No. 142”) requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible assethas a finite useful life, but the precise length of that life is not known, that intangible asset must be amortized over the best estimate of its useful life. At aminimum, Atlas will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortizationexpense on the customer contract intangible assets, which have an estimated life of 12 years and are amortized on a straight−line basis, was $0.5 million for thenine months ended September 30, 2005. There was no amortization expense on intangible assets recorded during the nine months ended September 30, 2004.Amortization expense related to intangible assets is estimated to be $1.1 million for each of the next five calendar years.

GoodwillAt December 31, 2004 and September 30, 2005, Atlas had $2.3 million and $80.2 million, respectively, of goodwill which was recognized in connection withconsummated acquisitions. Atlas tests its goodwill for impairment at each year end by comparing fair values to its carrying values. The evaluation of impairmentunder SFAS No. 142 requires the use of projections, estimates and assumptions as to the future performance

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of Atlas’ operations, including anticipated future revenue, expected future operating costs and the discount factor used. Actual results could differ fromprojections, resulting in revisions to Atlas’ assumptions and, if required, recognition of an impairment loss. Atlas’ test of goodwill at December 31, 2004 resultedin no impairment, and no impairment indicators have been noted as of September 30, 2005. Atlas will continue to evaluate its goodwill at least annually andwhen impairment indicators arise, and will reflect the impairment of goodwill, if any, within its consolidated statements of income in the period in which theimpairment is indicated.

Depreciation and Amortization

Atlas calculates its depreciation based on the estimated useful lives and salvage values of its assets. However, factors such as usage, equipment failure,competition, regulation or environmental matters could cause it to change its estimates, thus impacting the future calculation of depreciation and amortization.

Impairment of AssetsIn accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long−Lived Assets,” Atlas reviewslong−lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of long−lived assets may not be recoverable.Atlas determines if its long−lived assets are impaired by comparing the carrying amount of an asset or group of assets with the estimated undiscounted futurecash flows associated with such asset or group of assets. If the carrying amount is greater than the estimated undiscounted future cash flows, an impairment lossis recognized to reduce the carrying value to fair value. Atlas’ operations are subject to numerous factors which could affect future cash flows which we discussin “Risk Factors.” Atlas continuously monitors these factors and pursue alternative strategies to maintain or enhance cash flows associated with these assets;however, we cannot assure you that Atlas can mitigate the effects, if any, on future cash flows related to any changes in these factors.

Fair Value of Derivative Commodity ContractsAtlas enters into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133. Atlas enters into theseinstruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in marketprices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs andcondensate is sold. Under these swap agreements, Atlas receives a fixed price and pays a floating price based on certain indices for the relevant contract period.

Atlas formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy forundertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. Atlas assesses, both atthe inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of hedged items. If it isdetermined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrumentand the underlying commodity, Atlas will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will berecognized immediately within its consolidated statements of income.

Atlas records derivatives on the consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, Atlas recognizes the effectiveportion of changes in fair value in owners’ equity as accumulated other comprehensive income (loss) and reclassifies them to earnings as such transactions aresettled. For non−qualifying derivatives and for the ineffective portion of qualifying derivatives, Atlas recognizes changes in fair value within the consolidatedstatements of income as they occur. At December 31, 2004 and September 30, 2005, Atlas reflected net hedging liabilities on the consolidated balance sheets of$2.6 million and $46.7 million, respectively. Of the $46.4 million net loss in accumulated other comprehensive loss at September 30, 2005, Atlas will reclassify$22.7 million of losses to the consolidated statements of income over the next twelve month period as these contracts expire, and $23.7 million will bereclassified in later periods if the fair values of the instruments remain at current market

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values. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded within the consolidatedstatements of income while the hedge contract is open and may increase or decrease until settlement of the contract. Atlas recognized losses of $27,000 and $4.4million for the nine months ended September 30, 2004 and 2005, respectively, within the consolidated statements of income related to the settlement ofqualifying hedge instruments. Atlas also recognized losses of $0.7 million for the nine months ended September 30, 2005 and 2004, within the consolidatedstatements of income related to the change in market value of non−qualifying or ineffective hedges.

A portion of Atlas’ future natural gas sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivativeinstruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to revenue.

Volume MeasurementAtlas records amounts for natural gas gathering and transportation revenue, NGL transportation and processing revenue, natural gas sales and natural gaspurchases, and the sale of production based on volumetric calculations. Variances resulting from such calculations are inherent in Atlas’ business.

New Accounting StandardsIn May 2005, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 154, “Accounting Changes andError Corrections” (“SFAS No. 154”). SFAS No. 154 requires retrospective application to prior periods’ financial statements for changes in accounting principle.It also requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for whichretrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than beingreported in an income statement. The statement will be effective for accounting changes and corrections of errors made in fiscal years beginning afterDecember 15, 2005. The impact of SFAS No. 154 will depend on the nature and extent of any voluntary accounting changes and corrections of errors after theeffective date, but we do not currently expect SFAS No. 154 to have a material impact on our financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which will result in (a)more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with thoseobligations, and (c) more information about investments in long−lived assets because additional asset retirement costs will be recognized as part of the carryingamounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, “Accounting for Asset RetirementObligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a futureevent that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertaintyexists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligationshould be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficientinformation to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending afterDecember 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation isencouraged. Atlas does not expect FIN 47 to have a material impact on the consolidated financial statements.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (R) (revised 2004), “Share−Based Payment” (“SFAS No. 123 (R)”)which is a revision of SFAS No. 123, “Accounting for Stock−Based Compensation.” SFAS No. 123 (R) supersedes Accounting Principles Board Opinion(“APB”) No. 25, “Accounting for Stock Issued to Employees,” and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach to accounting inStatement 123 (R) requires all share−based payments to employees, including grants of employee stock options, to be recognized in the financial statementsbased on their fair values. Currently, Atlas follows APB No. 25 and its interpretations, which allow for valuation of

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share−based payments to employees at their intrinsic values. Under this methodology, Atlas recognizes compensation expense for phantom units granted only ifthe current market price of the underlying units exceeds the exercise price. SFAS No. 123 (R) is effective for us beginning January 1, 2006. Atlas does not expectSFAS No. 123 (R) to have a material impact on the consolidated financial statements.

Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward−looking quantitative and qualitative information about our potential exposure to marketrisks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and natural gas, NGL and condensate prices. The disclosuresare not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward−looking information providesindicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other thantrading.

All of Atlas’ assets and liabilities are denominated in U.S. dollars and, as a result, it does not have exposure to currency exchange risks.

Atlas is exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact Atlas’ results ofoperations, cash flows and financial position. Atlas manages these risks through regular operating and financing activities and periodic use of derivative financialinstruments. The following analysis presents the effect on Atlas’ results of operations, cash flows and financial position as if the hypothetical changes in marketrisk factors occurred on September 30, 2005. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possibleeffects that could impact Atlas’ business.

Interest Rate Risk. At September 30, 2005, Atlas had a $225.0 million revolving credit facility ($183.5 million outstanding) to fund the expansion of its existinggathering systems, acquire other natural gas gathering systems and fund working capital movements as needed. The weighted average interest rate for theseborrowings was 6.6% at September 30, 2005. Holding all other variables constant, a 1% change in interest rates would change interest expense by $1.8 million.

Commodity Price Risk. Atlas is exposed to commodity prices as a result of being paid for certain services in the form of commodities rather than cash. Forgathering services, Atlas receives fees for commodities from the producers to bring the raw natural gas from the wellhead to the processing plant. For processingservices, Atlas either receives fees or commodities as payment for these services, based on the type of contractual agreement. Based on the current portfolio ofgas supply contracts, Atlas is long condensate, NGL and natural gas positions. A 10% change in the average price of NGLs, natural gas and condensate Atlasprocesses and sells would result in a change to our 2005 consolidated annual income, excluding the effect of minority interests in Atlas net income, ofapproximately $2.1 million.

Atlas enters into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133. Atlas enters into theseinstruments to hedge its forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in marketprices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs andcondensate is sold. Under these swap agreements, Atlas receives a fixed price and pays a floating price based on certain indices for the relevant contract period.

Atlas formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective and strategy forundertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. Atlas assesses, both atthe inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cash flow of hedged items. If it isdetermined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrumentand the underlying commodity, Atlas will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will berecognized immediately within our consolidated statements of income.

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Derivatives are recorded on the consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, Atlas recognizes the effectiveportion of changes in fair value in owners’ equity as accumulated other comprehensive income (loss) and reclassifies them to earnings as such transactions aresettled. For non−qualifying derivatives and for the ineffective portion of qualifying derivatives, Atlas recognizes changes in fair value within the consolidatedstatements of income as they occur. At December 31, 2004 and September 30, 2005, Atlas reflected net hedging liabilities on its consolidated balance sheets of$2.6 million and $46.7 million, respectively. Of the $46.4 million net loss in accumulated other comprehensive income (loss) at September 30, 2005, Atlas willreclassify $22.7 million of losses to its consolidated statements of income over the next twelve month period as these contracts expire, and $23.7 million will bereclassified in later periods if the fair values of the instruments remain at current market values. Actual amounts that will be reclassified will vary as a result offuture price changes. Ineffective hedge gains or losses are recorded within Atlas’ consolidated statements of income while the hedge contract is open and mayincrease or decrease until settlement of the contract. Atlas recognized losses of $27,000 and $4.4 million for the nine months ended September 30, 2004 and2005, respectively, within our consolidated statements of income related to the settlement of qualifying hedge instruments. Atlas also recognized losses of $0.7million for the nine months ended September 30, 2005 and 2004, within its consolidated statements of income related to the change in market value ofnon−qualifying or ineffective hedges.

A portion of Atlas’ future natural gas sales is periodically hedged through the use of swaps and collar contracts. Realized gains and losses on the derivativeinstruments that are classified as effective hedges are reflected in the contract month being hedged as an adjustment to revenue.

As of September 30, 2005, Atlas had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Fixed – Price Swaps

Twelve Months Ended September30,

VolumesAverage fixed

priceFair valueliability(1)

(gallons) (per gallon) (in thousands)2006 38,586,000 $ 0.673 $ (16,742)2007 38,115,000 0.711 (12,188)2008 34,587,000 0.702 (9,037)2009 7,434,000 0.697 (1,781)

$ (39,748)

Natural Gas Fixed – Price Swaps




(MMbtu)(2) (per MMbtu) (in thousands)2006 3,923,000 $ 7.169 $ (5,767)2007 1,560,000 7.210 (1,658)2008 510,000 7.262 (1,037)

$ (8,462)

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Natural Gas Basis Swaps



priceFair value

asset(3)

(MMbtu)(2) (per MMbtu) (in thousands)2006 4,262,000 $ (0.517) $ 1,3762007 1,560,000 (0.522) 1,5842008 510,000 (0.544) 1,383

$ 4,343

Crude Oil Fixed – Price Swaps




(Bbls) (per Bbl) (in thousands)2006 67,800 $ 51.329 $ (1,056)2007 80,400 55.187 (844)2008 82,500 58.475 (414)

$ (2,314)

Crude Oil Options


Option type VolumesAverage strike


(Bbls) (per Bbl) (in thousands)2006 Puts

purchased 15,000 $ 30.00 $ —2006 Calls sold 15,000 34.25 (481)

$ (481)

Total net liability $ (46,662)

(1) Fair value based upon management estimates, including forecasted forward NGL prices as a function of forward NYMEX natural gas and light crude prices.

(2) MMbtu represents million British Thermal Units.

(3) Fair value based on forward NYMEX natural gas and light crude prices, as applicable.

In Atlas’ Appalachian operations, it is the beneficiary of natural gas gathering agreements with Atlas America under which Atlas receives gathering feesgenerally equal to a percentage, typically 16% of the selling price, of the natural gas it transports. Atlas is the beneficiary of, and consults with Atlas Americawith respect to, the hedging program it has established for its Appalachian natural gas production that mitigates the risks of Atlas’ percentage of proceedsagreement with it. Atlas does not currently engage in any interest rate or foreign currency exchange rate transactions, and as a result, it does not have exposure tothose types of derivative risks.

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BUSINESS


Our cash generating assets consist of our interests in Atlas Pipeline Partners, L.P., a publicly traded Delaware limited partnership. Atlas is a midstream energyservice provider engaged in the transmission, gathering and processing of natural gas in the Mid−Continent and Appalachian regions. Our interests in Atlas willinitially consist of a 100% ownership interest in the general partner of Atlas, Atlas Pipeline GP, which owns:


• all of the incentive distribution rights in Atlas, which entitle it to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed byAtlas as it reaches certain target distribution levels in excess of $0.42 per Atlas unit in any quarter; and

• 1,641,026 common units of Atlas, representing an approximate 12.8% limited partner interest in Atlas.At Atlas’ current quarterly distribution rate of $0.83 per common unit, aggregate quarterly cash distributions to us on all our interests in Atlas would beapproximately $5.0 million. Based on this distribution, we expect that our initial quarterly distribution will be $0.225 per unit, or $0.90 per unit on an annualizedbasis.

Our primary objective is to increase our cash distributions to our unitholders through growth at Atlas. Atlas has grown through strategic acquisitions and internalgrowth projects. Since Atlas’ initial public offering in January 2000, it has completed five acquisitions at an aggregate cost of approximately $516.7 million.Atlas’ business strategy is to create capital−efficient growth in distributable cash flow to maximize its distribution to its unitholders by, among other things, (1)maximizing cash flows from its existing businesses through marketing of its services and facilities and controlling its operating costs; (2) continuing to increasethe amount of its operating cash flow generated by long−term, fee−based contracts; (3) expanding its existing businesses through internal growth opportunities;(4) expanding its operations through strategic acquisitions; and (5) maintaining a flexible capital structure based on a strong balance sheet by financing its growththrough a balanced combination of debt and equity.

We intend to support Atlas in implementing its business strategy by assisting it in identifying, evaluating, and pursuing growth opportunities. In the future, wemay also support the growth of Atlas through the use of our capital resources, which could involve loans or capital contributions to Atlas to provide funding forthe acquisition of a business or asset or for an internal growth project. We may also provide Atlas with other forms of credit support, such as guarantees related tofinancing a project or other types of support related to a merger or acquisition transaction.

Atlas is required by its partnership agreement to distribute all of its cash on hand at the end of each quarter, less reserves established by its general partner in itssole discretion to provide for the proper conduct of Atlas’ business or to provide for future distributions. Atlas has increased the per unit quarterly cashdistribution on its common units by approximately 48%, from the quarterly distribution of $0.56 per unit declared for the first quarter of 2003 to $0.83 per unitdeclared for the fourth quarter of 2005. The following graph shows, for the period from the first quarter of 2003 through the fourth quarter of 2005: (i) Atlas’quarterly distributions per unit and (ii) total distributions by Atlas to us.

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While we, like Atlas, are structured as a limited partnership, our capital structure and cash distribution policy differ materially from those of Atlas. Most notably,our general partner does not have an economic interest in us and is not entitled to receive any distributions from us, and our capital structure does not includeincentive distribution rights. Therefore, all of our distributions are made on our common units, which is our only class of security outstanding.

Our ownership of Atlas’ incentive distribution rights entitles us to receive an increasing percentage of cash distributed by Atlas as it reaches certain targetdistribution levels. The rights entitle us to receive the following:

• 13.0% of all cash distributed in a quarter after each Atlas unit has received $0.42 for that quarter;

• 23.0% of all cash distributed after each Atlas unit has received $0.52 for that quarter; and

• 48.0% of all cash distributed after each Atlas unit has received $0.60 for that quarter.For the quarter ended December 31, 2005, Atlas declared a distribution of $0.83 per unit, which means we will receive 48.0% of the $0.23 incremental cashdistribution per unit in excess of the maximum target distribution level of $0.60 per unit. Because the incentive distribution rights currently participate at themaximum 48.0% target cash distribution level, future growth in distributions we receive from Atlas will not result from an increase in the target cash distributionlevel associated with the incentive distribution rights.

The graph set forth below demonstrates hypothetical cash distributions payable in respect of our interests in Atlas by showing the total cash allocated to us acrossan illustrative range of annualized cash distributions per unit made by Atlas. The graph illustrates the impact to us of Atlas raising or lowering its distributionfrom the most recently declared distribution of $0.83 per common unit ($3.32 on an annualized basis), which will be paid on February 14, 2006. This informationassumes:

• Atlas has 12,549,266 total units outstanding, representing the number of units outstanding at December 31, 2005; and

• through Atlas Pipeline GP, we own (i) 1,641,026 Atlas common units, representing an approximate 12.8% limited partner interest in Atlas, (ii) a 2.0%general partner interest in Atlas and (iii) all the incentive distribution rights.

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This information is presented for illustrative purposes only and is not intended to be a prediction of future performance and does not attempt to illustrate theimpact of changes in our or Atlas’ business, including changes that may result from changes in natural gas, NGL and condensate prices, changes in economicconditions, the impact of any future acquisitions or expansion projects or the issuance of additional units by Atlas. In addition, the level of cash distributions wereceive may be affected by the various risks associated with an investment in us and the underlying business of Atlas. Please read “Risk Factors.”

We intend to pay to our unitholders, on a quarterly basis, distributions equal to the cash we receive from Atlas, less certain reserves for expenses and other usesof cash, including:

• our general and administrative expenses, including expenses we will incur as the result of being a public company;

• capital contributions to maintain or increase our ownership interest in Atlas; and

• reserves our general partner believes prudent to maintain for the proper conduct of our business or to provide for future distributions.Based on Atlas’ current quarterly distribution, the number of our units outstanding and our expected level of expenses and reserves that our general partnerbelieves prudent to maintain, we expect that our initial quarterly distribution will be $0.225 per common unit, or $0.90 per unit on an annualized basis. Due toour ownership of Atlas’ incentive distribution rights, our cash flows are impacted by changes in Atlas’ distributions to a greater extent than those of Atlas’common unitholders.

If Atlas is successful in implementing its business strategy and increasing distributions to its unitholders, we would generally expect to increase distributions toour unitholders, although the timing and amount of any such increased distributions will not necessarily be comparable to the increased Atlas distributions.However, we cannot assure you that any distributions will be declared or paid. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Our common units and Atlas’ common units are unlikely to trade in simple relation or proportion to one another. Instead, while the trading prices of our commonunits and Atlas’ common units are likely to follow generally similar broad trends, the trading prices may diverge because, among other things:

• with respect to Atlas distributions, Atlas’ common unitholders have a priority over the incentive distribution rights; and

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• we participate in Atlas’ managing general partner’s distributions and the incentive distribution rights, and Atlas’ common unitholders do not; and

• we may in the future enter into other businesses separate from Atlas or any of its affiliates.


Overview

Atlas is a publicly−traded midstream energy services provider engaged in the transmission, gathering and processing of natural gas. Atlas conducts its businessthrough two operating segments: its Mid−Continent operations and its Appalachian operations.

Through its Mid−Continent operations, Atlas owns and operates:

• a 75% interest in a FERC−regulated, 565−mile interstate pipeline system, which we refer to as Ozark Gas Transmission, that extends from southeasternOklahoma through Arkansas and into southeastern Missouri and which has throughput capacity of approximately 322 MMcf/d;


• 1,765 miles of active natural gas gathering systems located in Oklahoma, Arkansas, northern Texas and the Texas panhandle, which transport gas fromwells and central delivery points in the Mid−Continent region to Atlas’ natural gas processing plants or Ozark Gas Transmission.

Through its Appalachian operations, Atlas owns and operates 1,500 miles of active natural gas gathering systems located in eastern Ohio, western New York andwestern Pennsylvania. Through an omnibus agreement and other agreements between Atlas and Atlas America, the parent of Atlas’ general partner and ourgeneral partner and a leading sponsor of natural gas drilling investment partnerships in the Appalachian Basin, Atlas gathers substantially all of the natural gasfor its Appalachian Basin operations from wells operated by Atlas America. Among other things, the omnibus agreement requires Atlas America to connect wellsit operates to Atlas’ gathering systems that are located within 2,500 feet of Atlas’ gathering systems. Atlas is also party to natural gas gathering agreements withAtlas America under which Atlas receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas it transports. Theseagreements are continuing obligations and have no specified term except that they will terminate if Atlas’ general partner is removed without cause.

Since Atlas’ initial public offering in January 2000, Atlas has completed five acquisitions at an aggregate cost of approximately $516.7 million, including, mostrecently, the October 2005 acquisition of Atlas Arkansas Pipeline LLC, which owns a 75% interest in NOARK, and the April 2005 acquisition of Elk City.

Both Atlas’ Mid−Continent and Appalachian operations are located in areas of abundant and long−lived natural gas production and significant new drillingactivity. The Ozark Gas Transmission system and Atlas’ gathering systems are connected to approximately 6,250 central delivery points or wells, giving Atlassignificant scale in its service areas. Atlas provides gathering and processing services to the wells connected to its systems, primarily under long−term contracts.Atlas provides fee−based, FERC−regulated transmission services through Ozark Gas Transmission under both long−term and short−term contractualarrangements. Atlas intends to increase the portion of the transmission services provided under long−term contracts. As a result of the location and capacity ofthe Ozark Gas Transmission system and Atlas’ gathering and processing assets, Atlas believes that it is strategically positioned to capitalize on the significantincrease in drilling activity in its service areas and the positive price differential across Ozark Gas Transmission, also known as basis spread. Atlas intends tocontinue to expand its business through strategic acquisitions and internal growth projects, including its plan to construct the Sweetwater gas plant, that increasedistributable cash flow per unit.

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The following table shows the pro forma gross margin for our operating units for the periods indicated:

Pro forma

Year ended December31,2004

Nine months endedSeptember30, 2005

(dollars in thousands)Mid−Continent:Velma and Elk City $ 43,294 51.2% $ 37,757 53.0%NOARK 22,480 26.6% 16,940 23.8%

$ 65,774 77.8% $ 54,697 76.8%Appalachia 18,800 22.2% 16,501 23.2%

$ 84,574 100.0% $ 71,198 100.0%

Please see “—Summary Historical Consolidated and Pro Forma Financial Data” for a definition of gross margin and a reconciliation of pro forma gross marginto our pro forma net income.

Recent Acquisitions

Acquisition of Atlas Arkansas and Controlling Interest in NOARKOn October 31, 2005, Atlas acquired from Enogex all of the outstanding equity of Atlas Arkansas for $165.3 million, including estimated related transactioncosts, plus $10.2 million for working capital adjustments. Atlas Arkansas owns a 75% interest in NOARK, with the remaining 25% interest being owned bySouthwestern. Before the closing of this acquisition, Atlas Arkansas converted from an Oklahoma corporation into an Oklahoma limited liability company andchanged its name from Enogex Arkansas Pipeline Company. The NOARK acquisition further expands Atlas’ activities in the Mid−Continent region and providesan additional source of fee−based cash flows from a FERC−regulated interstate pipeline system and an intrastate gas gathering system. NOARK’s geographicposition relative to Atlas’ other businesses and interconnections with major interstate pipelines also provides Atlas with internal growth opportunities. NOARK’sprincipal assets include:

• The Ozark Gas Transmission system, a 565−mile FERC−regulated interstate pipeline system which extends from southeast Oklahoma throughArkansas and into southeast Missouri and has a throughout capacity of approximately 322 MMcf/d. The system includes approximately 30 supply anddelivery interconnections and two compressor stations.

• The Ozark Gas Gathering system, a 365−mile intrastate natural gas gathering system, located in eastern Oklahoma and western Arkansas, and 11associated compressor stations.

Atlas financed the acquisition by borrowing under its senior secured credit facility. Atlas expects the NOARK acquisition to be immediately accretive to itsdistributable cash flow per unit.

Ozark Gas Transmission transports natural gas from receipt points in eastern Oklahoma and western Arkansas, where the Arkoma Basin is located, to interstatepipelines in northeastern and central Arkansas and to local distribution companies in Arkansas and Missouri. Ozark Gas Gathering provides access to natural gassupplies that are then transported through Ozark Gas Transmission. Ozark Gas Transmission’s revenue is comprised of FERC−regulated transmission fees thatare based on firm transportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates.The Ozark transmission and gathering systems transported an average of 163.9 MMcf/d during the nine months ended September 30, 2005, and 207.2 MMcf/dduring October 2005.

Atlas’ gas supply strategy in the Mid−Continent region is to establish long−term, value−oriented relationships with its producing customers. Atlas haslong−standing relationships with many of its Mid−Continent customers which account for a substantial majority of Atlas’ gathering and processing throughput.The Mid−Continent region, one of the most prolific natural gas−producing regions in North America, has recently experienced a significant increase in oil andgas drilling activity driven by long−term projections of continued growth in U.S. natural gas demand and the application of new drilling and

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production technologies. Atlas believes that the increased drilling activity in the Mid−Continent area, combined with the positive basis spread across Ozark GasTransmission, will result in increasing volumes gathered and transported on the Ozark Gas Gathering and Ozark Gas Transmission systems.

As part of the acquisition, Enogex agreed to redeem the 40% portion of NOARK’s 7.15% notes due 2018 for which it is severally liable as guarantor as promptlyas practicable after the closing. At the closing, Enogex deposited $32.2 million with UMB Bank, N.A., as escrow agent, in order to fulfill this redemptionobligation. The redemption of $26.4 million was completed on December 5, 2005. After the redemption, $39.6 million of notes remain outstanding for whichSouthwestern, the other partner in NOARK, will remain liable for the remaining 60% portion of the 7.15% notes. Under the NOARK partnership agreement,payments on the notes will be made from amounts otherwise distributable to Southwestern and, if that amount is insufficient, Southwestern is required to make acapital contribution to NOARK.

Acquisition of Elk CityIn April 2005, Atlas acquired all of the outstanding equity interests in Elk City for $196.0 million, including transaction costs. Elk City’s principal assets includeapproximately 300 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma and the Texas panhandle, a natural gas processing facilityin Elk City, Oklahoma, with a total capacity of approximately 130 MMcf/d, and a gas treating facility in Prentiss, Oklahoma, with a total capacity ofapproximately 200 MMcf/d. Gathered volumes averaged 242.3 MMcf/d for the nine months ended September 30, 2005. The system connects to over 300 receiptpoints. The acquisition expanded the scale of Atlas’ Mid−Continent operations and built upon its experience in processing and gathering. Atlas recentlycompleted three new gathering and compression projects in Elk City which have increased, and Atlas believes will continue to increase, gathered volumes andtotal gross margin. Atlas also plans to complete construction of a new natural gas processing facility in Oklahoma near its Prentiss treating facility in the thirdquarter of 2006, which we refer to as the Sweetwater gas plant. The new plant will be scaled to 120 MMcf/d of processing capacity. Along with the Sweetwatergas plant, Atlas will construct a gathering system to be located primarily in western Oklahoma and in the Texas panhandle, more specifically, Beckham andRoger Mills counties in Oklahoma and Hemphill County, Texas. Atlas anticipates that construction of the Sweetwater gas plant and associated gathering systemwill cost approximately $40.0 million and will generate cash flow of $8.0 million to $10.0 million annually.

Business StrategyAtlas’ primary objective is to increase cash flow and achieve sustainable, profitable growth while maintaining a strong credit profile and financial flexibility byexecuting the following strategies:

• Maximize cash flows from its existing businesses through efficient marketing of its services and facilities and control of its operating costs. Atlasintends to continue to control its operating costs by efficiently managing its existing and acquired businesses and achieving economies of scale. Atlashas additional capacity in its gathering systems and has, or can upgrade at minimal cost, the capacity at its processing and treating facilities. As a resultAtlas can readily increase the amount of natural gas it transports and processes.

• Continuing to increase the amount of its operating cash flow generated by long−term, fee−based contracts. Atlas intends to continue to securelong−term, fee−based contracts both in its existing operations and through strategic acquisitions in order to further diversify its contract mix.

• Expanding existing businesses through organic growth opportunities. Atlas continually evaluates opportunities to expand its operations through theconstruction of pipeline extensions to connect additional wells and access additional reserves. In addition, Atlas plans to complete the Sweetwater gasplant, a 120 MMcf/d natural gas processing plant near its Prentiss treatment plant, by the third quarter of 2006. Atlas believes that its agreements withAtlas America present a favorable source of organic growth and that its competitive position and customer relationships in the Mid−Continent regionwill continue to yield additional expansion opportunities.

• Expand operations through strategic acquisitions. Atlas’ recent acquisitions have provided geographic diversification and expanded the midstreamservices it provides. Atlas intends to continue

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to make accretive acquisitions of midstream energy assets such as natural gas gathering systems and natural gas and NGL transmission, processing andstorage facilities. Atlas will seek strategic opportunities in its current areas of operation, as well as other regions of the United States with significantnatural gas and oil reserves or with growing demand for natural gas and oil. Atlas believes that there will continue to be attractive acquisitionopportunities in the midstream sector of the energy industry.

• Maintain a flexible capital structure based on a strong balance sheet by financing its growth through a balanced combination of debt and equity. Toprovide financial flexibility to fund future acquisition and expansion opportunities, Atlas intends to continue to opportunistically access the capitalmarkets. Atlas intends to maintain a strong balance sheet by financing growth with a combination of long−term debt and equity. Including Atlas’ initialpublic offering in 2000, Atlas has accessed the equity markets six times, raising approximately $370.6 million in gross proceeds. Atlas expects to haveunused capacity under its revolving credit facility to finance system expansions, acquisitions and working capital needs. Historically, because of itsfinancial flexibility, Atlas has been able to take advantage of opportunities for expansion and optimization as they arise.

Competitive Strengths

Strategically positioned for internal growth.

Atlas is a leading provider of natural gas gathering services in the Appalachian and Anadarko Basins and the Arkoma Basin, and the Golden Trend area ofOklahoma and the Appalachian Basin and of natural gas processing services in Oklahoma. These regions are characterized by long−lived wells and substantialdeveloped and undeveloped natural gas reserves which Atlas believes will continue to promote significant drilling activity. Atlas provides gathering andprocessing services to over 6,250 wells and central delivery points. Atlas expects the breadth of its operations in its service areas, its customer focus and itsrelationship with Atlas America will allow Atlas to continue to connect new wells and capture new natural gas volumes quickly and cost effectively.Additionally, the NOARK acquisition increases its size and presence in the Mid−Continent region, including expanding Atlas’ operations east into the ArkomaBasin.

Diversified asset base.Atlas’ operations are divided between the active Mid−Continent Basin, including Arkansas, Oklahoma, southern Missouri, northern Texas and the Texaspanhandle, where Atlas transports, gathers, processes and treats third−party gas volumes, and the Appalachian Basin, where Atlas accesses new volumes throughlong−term gathering agreements with Atlas America. In addition, Atlas’ revenue is generated under a variety of contract structures, including FERC−regulatedtransmission fees from Ozark Gas Transmission, fixed fees from Atlas’ gathering and treating businesses, percentage−of−proceeds contracts from Atlas’gathering and processing businesses and, to a lesser extent, keep−whole contracts from Atlas’ Elk City processing plant, which Atlas may bypass during periodsof unfavorable processing margins.

Stability from long−term contracts and strong customer relationships.Atlas’ gas supply strategy in the Mid−Continent region is to establish long−term, value−oriented relationships with its producing customers. Atlas haslong−standing relationships with many of its Mid−Continent customers which account for a substantial majority of our gathering and processing throughput.Ozark Gas Transmission also has strong relationships with numerous shippers that contract for transmission services either on a short or long−term firm basis orinterruptible basis. In addition, Atlas’ Appalachian operations generate substantially all of their volumes under a long−term omnibus agreement with AtlasAmerica whereby Atlas America is required to commit to Atlas’ gathering system all wells it drills and operates that are within 2,500 feet of the system. Wellsunder this agreement are committed for the life of their respective leases, typically over 30 years.

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Relationship with Atlas America.

As a result of Atlas’ agreements with Atlas America, Atlas believes that the growth in the number of wells drilled by Atlas America and its affiliates in theAppalachian Basin will serve as an engine for its growth in the region. Atlas connected 411 Atlas America wells to its Appalachian gathering system for thetwelve months ended September 30, 2005, and 1,508 Atlas America wells from its inception in January 2000 through September 30, 2005.

Efficient assets that offer low maintenance capital expenditure requirements, system flexibility and superior customer service.Atlas’ transmission, gathering and processing systems carry low maintenance capital expenditure needs. In addition, a significant portion of Atlas’ existinggathering systems and processing plants are new or have been recently expanded or replaced. Atlas’ gathering systems provide its customers increased flexibilitythrough low pressure service and multiple pipeline interconnections, and its willingness to expand its systems quickly provides its customers with superiorcustomer service.

Favorable commercial agreements that reduce commodity price risk.Atlas derives substantially all of the operating income from its gathering and processing operations from fee−based and percentage−of−proceeds arrangements.Atlas has hedged a significant amount of its near−term equity natural gas production and equity NGL production from its processing operations, which it believesshould reduce volatility in its operating income. Furthermore, Atlas can bypass its Elk City processing plant during periods of unfavorable processing margins.Substantially all of the operating income generated by NOARK’s transmission and gathering assets is generated under fixed−fee agreements. In its Appalachianoperations, Atlas is the beneficiary of, and consults with Atlas America with respect to, the hedging program Atlas America has established for its Appalachiannatural gas production that mitigates the risks of Atlas’ percentage−of−proceeds agreement with it.

Experienced management and engineering team.Through Atlas’ general partner, Atlas has significant management and technical expertise. Atlas’ senior management team averages approximately 20 years ofexperience in the oil and natural gas industry and currently manages 91 public and private drilling investment partnerships. Atlas’ operational and technicalexpertise has enabled it to identify assets that have not been fully utilized and to improve their performance upon integration into Atlas’ operations.

The Midstream Natural Gas Gathering, Processing and Transmission IndustryThe midstream natural gas gathering and processing industry is characterized by regional competition based on the proximity of gathering systems andprocessing plants to producing natural gas wells.

The natural gas gathering process begins with the drilling of wells into natural gas or oil bearing rock formations. Once a well has been completed, the well isconnected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines that collect natural gas from points near producingwells and transport it to larger pipelines for further transmission. Gathering systems are operated at design pressures that will maximize the total throughput fromall connected wells.

While natural gas produced in some areas, such as the Appalachian Basin, does not require treatment or processing, natural gas produced in many other areas,such as Atlas’ Velma service area, is not suitable for long−haul pipeline transmission or commercial use and must be compressed, transported via pipeline to acentral processing facility, and then processed to remove the heavier hydrocarbon components such as NGLs and other contaminants that would interfere withpipeline transmission or the end use of the gas. Natural gas processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and remove theNGLs, enabling the treated, “dry” gas (stripped of liquids) to meet pipeline specification for long−haul transport to end users. After being separated from naturalgas at the processing plant, the mixed NGL stream, commonly referred to as “y−grade” or “raw mix,” is typically transported on pipelines to a centralized facilityfor

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fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline.

Natural gas transmission pipelines receive natural gas from producers, other mainline transmission pipelines, shippers and gathering systems through systeminterconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial end−users, utilities and other pipelines. Generallynatural gas transmission agreements generate revenue for these systems based on a fee per unit of volume transported.

Mid−Continent OperationsAtlas owns and operates a 565−mile interstate natural gas pipeline, approximately 2,565 miles of intrastate natural gas gathering systems, includingapproximately 800 miles of inactive pipeline, located in Oklahoma, Arkansas, southeast Missouri, northern Texas and the Texas panhandle, and two processingplants and one stand−alone treating facility in Oklahoma. The Mid−Continent operations were formed through Atlas’ acquisition of Spectrum in July 2004 andexpanded through the Elk City acquisition in April 2005 and the NOARK acquisition in October 2005. Ozark Gas Transmission transports natural gas fromreceipt points in eastern Oklahoma, including major intrastate pipelines, and western Arkansas, where the Arkoma Basin is located, to local distributioncompanies in Arkansas and Missouri and to interstate pipelines in northeastern and central Arkansas. Ozark Gas Gathering provides access to natural gas suppliesthat are then transported through Ozark Gas Transmission. Atlas’ gathering and processing assets service long−lived natural gas basins that continue toexperience an increase in drilling activity, including the Anadarko Basin and the Arkoma Basin and the Golden Trend area of Oklahoma. Atlas’ systems gathernatural gas from oil and natural gas wells and process the raw natural gas into merchantable, or residue gas, by extracting NGLs and removing impurities. In theaggregate, the Mid−Continent systems have approximately 1,160 receipt points, consisting primarily of individual connections and, secondarily, of centraldelivery points which are linked to multiple wells. Atlas’ gathering systems currently connect with interstate and intrastate pipelines operated by Ozark GasTransmission, ONEOK Gas Transportation, LLC, Southern Star Central Gas Pipeline, Inc., Panhandle Eastern Pipe Line Company, LP, Northern Natural GasCompany, CenterPoint Energy, Inc., ANR Pipeline Company, Texas Eastern, Mississippi River Transmission and Natural Gas Pipeline Company of America.

Mid−Continent OverviewThe heart of the Mid−Continent region is generally defined as running from Kansas through Oklahoma, branching into North and West Texas, southeast NewMexico as well as western Arkansas. The primary producing areas in the region include the Hugoton field in southwest Kansas, the Anadarko basin in westernOklahoma, the Permian basin in West Texas and the Arkoma basin in western Arkansas and eastern Oklahoma.

According to the Energy Information Administration, Oklahoma accounted for approximately 9.0% of total 2003 domestic natural gas production, or 1.6 Tcf.From 2000 to 2003, Oklahoma reserves, which were 15.4 Tcf at December 31, 2003, grew at an annual compound growth rate of 4.0%, significantly higher thantotal domestic reserves which grew at a rate of 2.1%. From 2000 to 2004, natural gas production in Oklahoma has grown at a compound annual rate of 1.2%while domestic natural gas production as a whole decreased at a compound annual rate of 0.5%.

The number of active drilling rigs serving Oklahoma has increased significantly over the last three years. In 2004, the number of active rigs drilling in Oklahomaaveraged 159 or a 75% increase over 2002. The areas served by our Velma, Elk City and NOARK assets have also experienced an increase in oil and natural gasdevelopment as evidenced by a growth in well completions in the counties that the Elk City system, Velma system and NOARK system serve. In 2004, wellpermits in Carter, Garvin, Grady, Stephens, Beckham and Washita counties totaled 809, a 20% increase compared to 2002.

FERC−Regulated Transmission SystemAtlas owns a 75% interest in NOARK, which owns a 565−mile FERC−regulated natural gas interstate pipeline extending from southeast Oklahoma throughArkansas and into southeast Missouri. Ozark Gas

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Transmission delivers natural gas via 30 supply and delivery interconnects with major intrastate and interstate pipelines, including Mississippi RiverTransmission Corp., Natural Gas Pipeline Company of America and Texas Eastern Transmission Corp., and receives natural gas from eight interconnects withintrastate pipelines, including Enogex, BP’s Vastar gathering system, Arkansas Oklahoma Gas Corporation, Arkansas Western Gas Company and ONEOK GasTransmission. Ozark Gas Transmission recently entered into a firm transportation agreement with Southwestern Energy Services Company under whichSouthwestern Energy Services has reserved capacity for 15,000 MMbtu/d through October 31, 2006.

Mid−Continent Gathering Systems

Velma. The Velma gathering system is located in the Golden Trend area of Southern Oklahoma and the Barnett Shale area of North Texas. As ofSeptember 30, 2005, the gathering system had approximately 1,100 miles of active pipeline with approximately 580 receipt points consisting primarily ofindividual connections and, secondarily, of central delivery points which are linked to multiple wells. The system includes approximately 800 miles of inactivepipeline, much of which can be returned to active status as local drilling activity warrants.

Elk City. The Elk City gathering system includes approximately 300 miles of natural gas pipelines located in the Anadarko Basin in western Oklahoma. TheElk City gathering system connects to over 300 receipt points, with a majority of the western end of the system located in close proximity to areas of high drillingactivity. Atlas recently completed three new gathering and compression projects which will increase gathered volumes and, Atlas believes, have a significantpositive effect on our earnings.

NOARK Gas Gathering. NOARK owns Ozark Gas Gathering, 365 miles of intrastate natural gas gathering pipeline located in eastern Oklahoma and westernArkansas, providing access to both the well−established Arkoma basin and the newly−exploited Fayetteville Shale. This system connects to approximately 250receipt points and compresses and transports gas to interconnections with Ozark Gas Transmission.

Processing PlantsVelma. The Velma processing plant, located in Stephens County, Oklahoma, is a single−train twin−expander cryogenic facility with a natural gas capacity ofapproximately 100 MMcf/d. The Velma plant is one of only two facilities in the area that is capable of treating both high−content hydrogen sulfide and carbondioxide gas. Atlas sells natural gas to purchasers at the tailgate of the Velma plant and sells NGL production to ONEOK Hydrocarbons Company. The Velmaoperations gather and process natural gas for approximately 150 producers. Atlas has made capital expenditures at the facility to improve its efficiency andcompetitiveness, including by implementing electric−powered compressors rather than higher−cost natural gas−powered compressors used by many of Atlas’competitors, which results in higher revenue from higher efficiency and lower fuel costs. In addition, Atlas recently completed a compression expansion projectthat increased processing capacity by 30 MMcf/d.

Elk City. The Elk City processing plant, located in Beckham County, Oklahoma, is a twin−train cryogenic natural gas processing plant with a total capacity ofapproximately 130 MMcf/d. Atlas sells natural gas to purchasers at the tailgate of its Elk City processing plant and sells NGL production to ONEOKHydrocarbons Company. The Prentiss treating facility, also located in Beckham County, is an amine treating facility with a total capacity of approximately 200MMcf/d. Atlas’ Elk City operations gather and process gas for more than 135 producers.

Atlas plans to complete construction of the Sweetwater gas processing facility near its Prentiss treatment plant by mid−2006. The new plant will initially bescaled to 120 MMcf/d of processing capacity. Along with the plant, Atlas will construct a gathering system to be located primarily in Beckham and Roger Millscounties in Oklahoma and Hemphill County, Texas. Atlas anticipates that construction of the plant and associated gathering system will cost approximately $40.0million and generate cash flow of $8.0 million to $10.0 million annually.

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Enville. Atlas’ Enville, Oklahoma gas plant is currently inactive and is used as a field compression booster station.

NOARK PartnershipNOARK is an Arkansas limited partnership in which Atlas Arkansas owns a 74% general partner interest and a 1% limited partner interest and Southwesternowns a 25% general partner interest. The current configuration of NOARK’s assets was completed in 1998 when Enogex acquired its interest in the partnership,which at that point owned Ozark Gas Gathering, and acquired Ozark Gas Transmission and certain Warren Petroleum gathering assets and contributed them tothe partnership.

The partnership is managed by a five−member management committee comprised of the partnership’s project leader appointed by Atlas Arkansas, subject toSouthwestern’s consent which cannot be unreasonably withheld, two members appointed by Atlas Arkansas and two members appointed by Southwestern. Themanagement committee determines whether to distribute cash, may issue mandatory capital calls to the partners and may conduct expansion projects. Anexpansion to the system not included in an approved budget requires an 80% vote of the partners; if a partner does not consent to an expansion within 30 days,the other partner may fund the project and receive a cash distribution equal to all of the net operating income attributable to the project until it has received 200%of its capital contribution, before the non−consenting partner receives distributions attributable to the project.

Under the partnership agreement, day−to−day management of the partnership’s operations is the responsibility of the project leader, who will be an employee ofAtlas America. Atlas Arkansas has the sole power to remove the project leader and, upon a vacancy in that position, to propose a new project leader, subject tothe consent of Southwestern, not to be unreasonably withheld.

As described under “—Acquisition of Atlas Arkansas and Controlling Interest in NOARK,” NOARK’s subsidiary, NOARK Pipeline Finance, L.L.C., hasoutstanding $66.0 million in principal amount of 7.15% notes due in 2018 outstanding at November 30, 2005. Liability under the notes is allocated 40% to us, assuccessor to Enogex upon acquisition, and 60% to Southwestern, and the parties are several guarantors for their respective allocations. As part of the NOARKacquisition, Enogex agreed to redeem its portion of the notes as promptly as practicable after the closing. The redemption of $26.4 million of the notes wascompleted on December 5, 2005. After the redemption, $39.6 million of notes remain outstanding, for which Southwestern will remain liable. Under thepartnership agreement, interest and principal payments on the notes will be made from amounts otherwise distributable to Southwestern and, if that amount isinsufficient, Southwestern is required to make a capital contribution to NOARK. NOARK distributes cash available for distribution after amounts payable on thenotes to the partners in accordance with their percentage interests.

Natural Gas SupplyIn the Mid−Continent, Atlas has gas purchase, gathering and processing agreements with approximately 250 producers with terms ranging from one month to 15years. These agreements provide for the purchase or gathering of gas under fixed−fee, percentage−of−proceeds or keep−whole arrangements. Most of theagreements provide for compression, treating, and/or low volume fees. Producers generally provide, in−kind, their proportionate share of compressor fuelrequired to gather the gas and to operate the Velma and Elk City processing plants. In addition, the producers generally bear their proportionate share ofgathering system line loss and, except for keep−whole arrangements, bear gas plant “shrinkage,” or the gas consumed in the production of NGLs.

Atlas has enjoyed long−term relationships with the majority of its Mid−Continent producers. For instance, on the Velma system, where Atlas has producerrelationships going back over 20 years, Atlas’ top four producers, which accounted for approximately 60% of its Velma volumes for the year endedDecember 31, 2004, have recently executed renegotiated contracts with primary terms running into 2009 and 2010. At the end of the primary terms, most of thecontracts with producers on Atlas’ gathering systems have evergreen term extensions.

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Natural Gas and NGL Marketing

Atlas sells natural gas to purchasers at the tailgate of both the Velma and Elk City plants and at various delivery points on Ozark Gas Gathering. During the yearended December 31, 2004, in its Velma operations, ONEOK Energy Marketing and Trading accounted for 31% of the residue natural gas sales and TenaskaMarketing Ventures accounted for 12% of such sales. Atlas currently sells the majority of its residue natural gas at the average of ONEOK Gas Transportation,LLC and Southern Star Central Gas Pipeline first−of−month indices as published in Inside FERC. The Velma plant has access to ONEOK Gas Transportation, anintrastate pipeline, and Southern Star Central Gas Pipeline, an interstate pipeline. In Atlas’ Elk City operations, Atlas sells substantially all of the residue gas toONEOK Energy Marketing, at first−of−month index pricing. The Elk City plant has access to five major interstate and intrastate downstream pipelines: NaturalGas Pipe Line of America, Panhandle Eastern Pipeline Co., CenterPoint Energy Gas Transmission Company, Northern Natural Gas Company and Enogex. OzarkGas Gathering gas prices are generally based on Texas Eastern “East LA” index as published in Inside FERC and have historically been sold to affiliates ofEnogex and Southwestern.

Atlas sells its NGL production to ONEOK Hydrocarbons Company under two separate agreements. Under the Velma agreement, Atlas has the right to elect on amonthly basis until January 31, 2006 whether the NGLs are sold into the Mont Belvieu or Conway markets. After that, NGLs will be sold on a 50% MontBelvieu/50% Conway combined price. NGLs are priced at the average monthly Oil Price Information Service, or OPIS, price for the selected market. The Velmaagreement has an initial term expiring February 1, 2011. NGL production from Atlas’ Elk City plant is also sold to ONEOK Hydrocarbons Company based onConway OPIS postings. The Elk City agreement has an initial term expiring October 1, 2008.

Condensate is collected at the Velma gas plant and around the Velma gathering system and sold for Atlas’ account to SemGroup, L.P. and EnerWest Tradingwhile that collected at Elk City is sold to TEPPCO Crude Oil, L.P.

Natural Gas and NGL HedgingAtlas’ Mid−Continent operations are exposed to certain commodity price risks. These risks result from either taking title to natural gas and NGLs, includingcondensate, or being obligated to purchase natural gas to satisfy contractual obligations with certain producers. Atlas mitigates a portion of these risks through acomprehensive risk management program which employs a variety of hedging tools. The resulting combination of the underlying physical business and thefinancial risk management program is a conversion from a physical environment that consists of floating prices to a risk−managed environment that ischaracterized by fixed prices.

Atlas (a) purchases natural gas and subsequently sells processed natural gas and the resulting NGLs, (b) purchases natural gas and subsequently sells theunprocessed gas, or (c) transports and/or processes the natural gas for a fee without taking title to the commodities. Scenario (b) exposes Atlas to a generallyneutral price risk (long sales approximate short purchases) while scenario (c) does not expose Atlas to any price risk; in both scenarios, risk management is notrequired.

Atlas is exposed to commodity price risks when natural gas is purchased for processing. The amount and character of this price risk is a function of Atlas’contractual relationships with natural gas producers, or, alternatively, a function of cost of sales. Atlas is therefore exposed to price risk at a gross profit levelrather than revenue level. These cost−of−sales or contractual relationships are generally of two types:

• Percentage−of−proceeds: requires Atlas to pay a percentage of revenue to the producer. This results in Atlas being net long physical natural gas andNGLs.

• Keep−whole: requires Atlas to deliver the same quantity of natural gas at the delivery point as Atlas received at the receipt point; any resulting NGLsproduced belong to Atlas. This results in Atlas being long physical NGLs and short physical natural gas.

Atlas hedges a portion of these risks by using fixed−for−floating swaps, which result in a fixed price, or by utilizing the purchase or sale of options, which resultin a range of fixed prices.

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Atlas recognizes gains and losses from the settlement of its hedges in revenue when Atlas sells the associated physical residue natural gas or NGLs. Any gain orloss realized as a result of hedging is substantially offset in the market when Atlas sells the physical residue natural gas or NGLs. All of Atlas’ hedges arecharacterized as cash flow hedges as defined in Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and HedgingAccounting.” Atlas determines gains or losses on open and closed hedging transactions as the difference between the hedge price and the physical price. Thismark−to−market methodology uses daily closing NYMEX prices when applicable and an internally−generated algorithm for hedged commodities that are nottraded on a market. To ensure that these financial instruments will be used solely for hedging price risks and not for speculative purposes, Atlas has established ahedging committee to review its hedges for compliance with Atlas’ hedging policies and procedures. In addition, Atlas does not enter into a hedge where itcannot offset the hedge with physical residue natural gas or NGL sales.

Appalachian Basin OperationsAtlas owns and operates approximately 1,500 miles of intrastate gas gathering systems located in eastern Ohio, western New York and western Pennsylvania.Atlas’ Appalachian operations serve approximately 5,100 wells with an average throughput of 54.8 MMcf/d of natural gas for the nine months endedSeptember 30, 2005. Atlas’ gathering systems provide a means through which well owners and operators can transport the natural gas produced by their wells tointerstate and public utility pipelines for delivery to customers. To a lesser extent, Atlas’ gathering systems transport natural gas directly to customers. Thesegathering systems connect with public utility pipelines operated by Peoples Natural Gas Company, National Fuel Gas Supply, Tennessee Gas Pipeline Company,National Fuel Gas Distribution Company, East Ohio Gas Company, Columbia Gas of Ohio, Consolidated Natural Gas Co., Texas Eastern Pipeline, ColumbiaGas Transmission Corp., Equitrans Pipeline Company, Gatherco Incorporated and Equitable Utilities. These systems are strategically located in the AppalachianBasin, a region characterized by long−lived, predictable natural gas reserves that are close to major eastern U.S. markets.

Appalachian Basin OverviewThe Appalachian Basin includes the states of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee. It is the most matureoil and gas producing region in the United States, having established the first oil production in 1859. In addition, the Appalachian Basin is strategically locatednear the energy−consuming regions of the mid−Atlantic and northeastern United States which has historically resulted in Appalachian producers selling theirnatural gas at a premium to the benchmark price for natural gas on the NYMEX.

According to the Energy Information Administration, a branch of the U.S. Department of Energy, in 2003 there were 22.4 Tcf of natural gas consumed in theUnited States which represented approximately 22.9% of the total energy used. The Appalachian Basin accounted for approximately 3.3% of total 2003 domesticnatural gas production, or 647.9 Bcf. Additionally, in 2003 there were approximately 145,189 gas wells in the Appalachian Basin which represented roughly36.9% of the total number of gas wells in the United States. Of those wells, Atlas America and its drilling investment partnerships own interests in approximately5,755 proved developed producing wells, 84% of which Atlas America operated in 2004.

Furthermore, according to the Natural Gas Annual 2003, an annual report published by the Energy Information Administration, Office of Oil and Gas, theAppalachian Basin holds 10.9 Tcf of economically recoverable gas reserves, representing approximately 5.8% of total domestic reserves as of December 31,2003. World Oil magazine, in its February 2005 issue, predicted that approximately 5,316 oil and gas wells will be drilled in the Appalachian Basin during 2005,approximately 13.3% of the total number of wells they predict will be drilled in the United States during 2005, and an increase of 8% over the number ofAppalachian Basin wells estimated to have been drilled during 2004, compared to an increase of 7.2% in the wells drilled in the United States from 2004 to 2005.

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Natural Gas Supply

Substantially all of the natural gas Atlas transports in the Appalachian Basin is derived from wells operated by Atlas America, a leading sponsor of natural gasdrilling investment partnerships in the Appalachian Basin. Atlas America is the corporate parent of Atlas’ general partner and our general partner. Atlas is partyto an omnibus agreement with Atlas America which is intended to maximize the use and expansion of its gathering systems and the amount of natural gas whichAtlas transports in the region. Among other things, the omnibus agreement requires Atlas America to connect to Atlas’ gathering systems wells it operates thatare located within 2,500 feet of Atlas’ gathering systems. Atlas America can require Atlas to extend its lines to connect an Atlas America−operated well locatedmore than 2,500 feet from Atlas’ gathering system if it extends a flow line to within 1,000 feet; for other Atlas America−operated wells located more than 2,500feet from Atlas’ gathering systems, Atlas has a right to extend its lines. Atlas is also party to natural gas gathering agreements with Atlas America under whichAtlas receives gathering fees generally equal to a percentage, typically 16%, of the selling price of the natural gas Atlas transports. From the inception of Atlas’operations in January 2000 through September 30, 2005, Atlas connected 2,040 new wells to its Appalachian gathering system, 433 of which were added throughacquisitions of other gathering systems. For the three months ended September 30, 2005, Atlas connected 151 wells to its gathering system and for the 12 monthsended September 30, 2005, Atlas connected 442 wells. Atlas’ ability to increase the flow of natural gas through its gathering systems and to offset the naturaldecline of the production already connected to its gathering systems will be determined primarily by the number of wells drilled by Atlas America and connectedto Atlas’ gathering systems and by Atlas’ ability to acquire additional gathering assets.

Natural Gas RevenueAtlas’ Appalachian Basin revenue is determined primarily by the amount of natural gas flowing through its gathering systems and the price received for thisnatural gas. Atlas has an agreement with Atlas America under which Atlas America pays Atlas gathering fees generally equal to a percentage, typically 16%, ofthe gross or weighted average sales price of the natural gas Atlas transports subject, in most cases, to minimum prices of $0.35 or $0.40 per Mcf. During the yearended December 31, 2004, Atlas received gathering fees averaging $0.96 per Mcf and for the nine months ended September 30, 2005, Atlas received gatheringfees averaging $1.10 per Mcf. Atlas charges other operators fees negotiated at the time Atlas connects their wells to its gathering systems or, in a pipelineacquisition, that were established by the entity from which Atlas acquired the pipeline.

Because Atlas does not buy or sell gas in connection with its Appalachian operations, Atlas does not engage in hedging. Atlas America maintains a hedgingprogram. Since Atlas receives transportation fees from Atlas America generally based on the selling price received by Atlas America, these physical hedgesmitigate the risk of Atlas’ percentage−of−proceeds arrangements.

Relationship with Atlas AmericaAtlas began its operations in January 2000 by acquiring the gathering systems of Atlas America. Atlas America, through its interest in us, will own a limitedpartner interest and general partner interest in Atlas after this offering through its ownership of our general partner, Atlas Pipeline Holdings GP, LLC. AtlasAmerica and its affiliates sponsor limited and general partnerships to raise funds from investors to explore for, develop and produce natural gas and, to a lesserextent, oil from locations in eastern Ohio, western New York and western Pennsylvania. Atlas’ gathering systems are connected to approximately 4,550 wellsdeveloped and operated by Atlas America in the Appalachian Basin. Through agreements between Atlas and Atlas America, Atlas gathers substantially all of thenatural gas for its Appalachian Basin operations from wells operated by Atlas America.

Omnibus AgreementUnder the omnibus agreement, Atlas America and its affiliates agreed to add wells to the gathering systems and provide consulting services when Atlasconstructs new gathering systems or extends existing

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systems. The omnibus agreement also imposes conditions upon Atlas’ general partner’s disposition of its general partner interest in Atlas. The omnibusagreement is a continuing obligation, having no specified term or provisions regarding termination except for a provision terminating the agreement if Atlas’general partner is removed as general partner without cause. The omnibus agreement may not be amended without the approval of the conflicts committee of themanaging board of Atlas’ general partner if, in the reasonable discretion of Atlas’ general partner, such amendment will adversely affect the common unitholders.Unitholders do not have explicit rights to approve any termination or material modification of the omnibus agreement, as stated in the accompanying prospectusunder “Atlas’ Partnership Agreement—Limited Voting Rights.” We anticipate that the conflicts committee of Atlas would submit to the common unitholders fortheir approval any proposal to terminate or amend the omnibus agreement if Atlas’ general partner determines, in its reasonable discretion, that the termination oramendment would materially adversely affect Atlas’ common unitholders.

Well Connections

Under the omnibus agreement, with respect to any well Atlas America drills and operates for itself or an affiliate that is within 2,500 feet of one of our gatheringsystems, Atlas America must, at its sole cost and expense, construct small diameter (two inches or less) sales or flow lines from the wellhead of any such well toa point of connection to the gathering system. Where an Atlas America Well is located more than 2,500 feet from one of Atlas’ gathering systems, but AtlasAmerica has extended the flow line from the well to within 1,000 feet of the gathering system, Atlas America has the right to require Atlas, at its cost andexpense, to extend its gathering system to connect to that well. With respect to other Atlas America Wells that are more than 2,500 feet from Atlas’ gatheringsystems, Atlas has the right, at its cost and expense, to extend its gathering system to within 2,500 feet of the well and to require Atlas America, at its cost andexpense, to construct up to 2,500 feet of flow line to connect to the gathering system extension. If Atlas elects not to exercise its right to extend its gatheringsystems, Atlas America may connect an Atlas America Well to a natural gas gathering system owned by someone other than Atlas or one of Atlas’ subsidiariesor to any other delivery point; however, Atlas will have the right to assume the cost of construction of the necessary flow lines, which then become Atlas’property and part of Atlas’ gathering systems.

Consulting Services. The omnibus agreement requires Atlas America to assist Atlas in identifying existing gathering systems for possible acquisition and toprovide consulting services to Atlas in evaluating and making a bid for these systems. Atlas America must give Atlas notice of identification by Atlas America orany of its affiliates of any gathering system as a potential acquisition candidate, and must provide Atlas with information about the gathering system, its sellerand the proposed sales price, as well as any other information or analyses compiled by Atlas America with respect to the gathering system. Atlas will have 30days to determine whether it wants to acquire the identified system and advise Atlas America of this intent. If Atlas intends to acquire the system, Atlas has anadditional 60 days to complete the acquisition. If Atlas does not complete the acquisition, or advise Atlas America that it does not intend to acquire the system,then Atlas America may do so.

Gathering System Construction. The omnibus agreement requires Atlas America to provide Atlas with construction management services if Atlas determinesto expand one or more of its gathering systems. Atlas must reimburse Atlas America for its costs, including an allocable portion of employee salaries, inconnection with Atlas America’s construction management services.

Disposition of Interest in Our General Partner. Direct and indirect wholly−owned subsidiaries of Atlas America act as the general partners, operators ormanagers of the drilling investment partnerships sponsored by Atlas America. Atlas’ general partner is a subsidiary of Atlas America. Under the omnibusagreement, those subsidiaries, including Atlas’ general partner, that currently act as the general partners, operators or managers of partnerships sponsored byAtlas America must also act as the general partners, operators or managers for all new drilling investment partnerships sponsored by Atlas America. AtlasAmerica and its affiliates may not divest their ownership of Atlas’ general partner entity without divesting their ownership of the other entities to the sameacquirer, except that Atlas America is permitted to transfer its interest in Atlas’ general partner to a wholly− or majority−owned direct or indirect subsidiary aslong as Atlas America continues to control the new entity. For these purposes, divestiture means a sale of all or substantially all of

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the assets of an entity, the disposition of more than 50% of the capital stock or equity interest of an entity, or a merger or consolidation that results in AtlasAmerica and its affiliates, on a combined basis, owning, directly or indirectly, less than 50% of the entity’s capital stock or equity interest, but excludes pledgesto a lender in connection with a secured funding arrangement. Atlas’ general partner has pledged its interests in Atlas as security for the revolving credit facilityof Atlas America.

Natural Gas Gathering Agreements

Under the master natural gas gathering agreement, Atlas receives a fee from Atlas America for gathering natural gas, determined as follows:

• for natural gas from well interests allocable to Atlas America or its affiliates (excluding general or limited partnerships sponsored by them) that wereconnected to Atlas’ gathering systems at February 2, 2000, the greater of $0.40 per Mcf or 16% of the gross sales price of the natural gas transported;

• for (i) natural gas from well interests allocable to general and limited partnerships sponsored by Atlas America that drill wells on or after December 1,1999 that are connected to Atlas’ gathering systems, (ii) natural gas from well interests allocable to Atlas America or its affiliates (excluding general orlimited partnerships sponsored by them) that are connected to Atlas’ gathering systems after February 2, 2000, and (iii) well interests allocable to thirdparties in wells connected to Atlas’ gathering systems at February 2, 2000, the greater of $0.35 per Mcf or 16% of the gross sales price of the naturalgas transported; and

• for natural gas from well interests operated by Atlas America and drilled after December 1, 1999 that are connected to a gathering system that is notowned by Atlas and for which Atlas assumes the cost of constructing the connection to that gathering system, an amount equal to the greater of $0.35per Mcf or 16% of the gross sales price of the natural gas transported, less the gathering fee charged by the other gathering system.

Atlas America receives gathering fees from contracts or other arrangements with third party owners of well interests connected to Atlas’ gathering systems.However, Atlas America must pay gathering fees owed to Atlas from its own resources regardless of whether Atlas America receives payment under thosecontracts or arrangements.

The master natural gas gathering agreement is a continuing obligation and, accordingly, has no specified term or provisions regarding termination. However, ifAtlas’ general partner is removed as the general partner without cause, then no gathering fees will be due under the agreement with respect to new wells drilledby Atlas America.

The master natural gas gathering agreement may not be amended without the approval of the conflicts committee of the managing board of Atlas’ general partnerif, in the reasonable discretion of Atlas’ general partner, such amendment will adversely affect the common unitholders. Unitholders do not have explicit rights toapprove any termination or material modification of the master natural gas gathering agreement, as stated in the accompanying prospectus under “Atlas’Partnership Agreement—Limited Voting Rights.” Atlas anticipates that the conflicts committee would submit to the common unitholders for their approval anyproposal to terminate or amend the master natural gas gathering agreement if Atlas’ general partner determines, in its reasonable discretion, that the terminationor amendment would materially adversely affect Atlas’ common unitholders.

In addition to the master natural gas gathering agreement, Atlas has three other gas gathering agreements with subsidiaries of Atlas America. Under two of theseagreements, relating to wells located in southeastern Ohio which Atlas America acquired from Kingston Oil Corporation and wells located in Fayette County,Pennsylvania which Atlas America acquired from American Refining and Exploration Company, Atlas receives a fee of $0.80 per Mcf. Under the thirdagreement, which covers wells owned by third parties unrelated to Atlas America or the investment partnerships it sponsors, Atlas receives fees that rangebetween $0.20 to $0.29 per Mcf or between 10% to 16% of the weighted average sales price for the natural gas Atlas transports.

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Atlas recently amended the gas gathering agreements with Atlas America to provide that the “gross sales price,” for purposes of the agreements, will mean theprice that is actually received, adjusted to take into account proceeds received or payments made pursuant to financial hedging arrangements.

CompetitionAtlas has encountered competition in acquiring midstream assets owned by third parties. In several instances Atlas submitted bids in auction situations and indirect negotiations for the acquisition of such assets and were either outbid by others or were unwilling to meet the sellers’ expectations. In the future, Atlasexpects to encounter equal if not greater competition for midstream assets because, as natural gas prices increase, the economic attractiveness of owning suchassets increases.

Mid−ContinentIn Atlas’ Mid−Continent service area, Atlas competes for the acquisition of well connections with several other gathering/servicing operations. These operationsinclude plants operated by Duke Energy Field Services, ONEOK Field Services and Enbridge. Atlas believes that the principal factors upon which competitionfor new well connections is based are:

• the price received by an operator for its production after deduction of allocable charges, principally the use of the natural gas to operate compressors;and

• responsiveness to a well operator’s needs, particularly the speed at which a new well is connected by the gatherer to its system.Atlas believes that its electric compressors operate more efficiently than the gas−operated compressors used by its competitors. As a result, Atlas believes that itcan operate as or more cost−effectively than its competitors. Atlas also believes that its relationships with operators connected to its system are good and thatAtlas presents an attractive alternative for producers. However, if Atlas cannot compete successfully, Atlas may be unable to obtain new well connections and,possibly, could lose wells already connected to its systems.

Being a regulated entity, Ozark Gas Transmission faces somewhat more indirect competition that is more regional or even national in character. CenterPointEnergy, Inc.’s interstate system is the nearest direct competitor.

Appalachian BasinAtlas’ Appalachian Basin operations do not encounter direct competition in their service areas since Atlas America controls the majority of the drillable acreagein each area. However, because Atlas’ Appalachian Basin operations principally serve wells drilled by Atlas America, Atlas is affected by competitive factorsaffecting Atlas America’s ability to obtain properties and drill wells, which affects its ability to expand its gathering systems and to maintain or increase thevolume of natural gas it transports and, thus, its transportation revenue. Atlas America also may encounter competition in obtaining drilling services fromthird−party providers. Any competition it encounters could delay Atlas America in drilling wells for its sponsored partnerships, and thus delay the connection ofwells to Atlas’ gathering systems. These delays would reduce the volume of gas Atlas otherwise would have transported, thus reducing Atlas’ potentialtransportation revenue.

As Atlas’ omnibus agreement with Atlas America generally requires it to connect wells it operates to Atlas’ system, Atlas does not expect any direct competitionin connecting wells drilled and operated by Atlas America in the future. In addition, Atlas occasionally connects wells operated by third parties. During 2004,Atlas connected 17 third party wells and for the first nine months of 2005, Atlas connected 16 third party wells.

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Contracts and Customer Relationships

In Atlas’ Mid−Continent operations, Atlas either purchases gas from producers, or intermediaries, into receipt points on its systems and then sells the gas, andproduced NGLs, if any, off of delivery points on its systems, or Atlas transports gas across its systems, from receipt to delivery point, without taking title to thegas. Beyond the distinction of purchasing or transporting gas, Atlas has a variety of contractual relationships with its producers and shippers, including fixed−fee,percentage−of−proceeds and keep−whole. Ozark Gas Transmission’s revenue is comprised of FERC−regulated transmission fees that are based on firmtransportation rates and, to the extent capacity is available following the reservation of firm system capacity, interruptible transportation rates. Under the fixed feecontracts, Atlas provides gathering, compression, treating and dehydration services to its customers for a flat fee. Gross margin from fee−based services dependssolely on throughput volume and is not affected by changes in commodity prices. Under the percentage−of−proceeds contracts, Atlas purchases natural gas at thewellhead, processes the natural gas and sells the plant residue gas and NGLs at market−based prices, remitting to producers a percentage of the proceeds. Underkeep−whole contracts, Atlas gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs at market price. The extraction of theNGLs lowers the Btu content of the natural gas. Therefore, under keep−whole contracts, Atlas must replace these Btus by either purchasing natural gas at marketprices or making a cash payment to the producer and Atlas’ profitability is dependent upon the spread between the price of natural gas, Atlas’ feedstock, andNGLs, Atlas’ “manufactured” product. The gross margin associated with each of these contractual arrangements can vary from period to period due to a varietyof factors, including changing prices of natural gas and NGLs, producers’ optionality between contract types (e.g., percentage−of−proceeds and keep−whole),and producers’ optionality between transporting and selling gas.

Substantially all of the gas Atlas transports in its Appalachian operations is under a percentage−of−proceeds contract with Atlas America where Atlas calculatesits transportation fee as a percentage of the price of the natural gas it transports. The natural gas Atlas transports in its Appalachian operations does not requireprocessing.

Regulation

Regulation by FERC of Interstate Natural Gas PipelinesFERC regulates Atlas’ interstate natural gas pipeline interests. Through Atlas Arkansas, Atlas owns a 75% interest in NOARK, which owns Ozark GasTransmission. Ozark Gas Transmission transports natural gas in interstate commerce. As a result, Ozark Gas Transmission qualifies as a “natural gas company”under the Natural Gas Act and is subject to the regulatory jurisdiction of FERC. In general, FERC has authority over natural gas companies that provide naturalgas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:

• rate structures;

• rates of return on equity;

• recovery of costs;

• the services that our regulated assets are permitted to perform;

• the acquisition, construction and disposition of assets; and

• to an extent, the level of competition in that regulated industry.Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstatecommerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction ofnew facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, theinitiation and discontinuation of services, and various other matters. Natural gas companies may not charge rates that have been determined not to be just andreasonable

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by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipelinerates or terms and conditions of service.

The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC−approved tariffs. Pursuant toFERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure youthat FERC will continue to pursue its approach of pro−competitive policies as it considers matters such as pipeline rates and rules and policies that may affectrights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against Ozark Gas Transmission’sFERC−approved rates could have an adverse impact on our revenue associated with providing transmission services.

Gathering Pipeline RegulationSection 1(b) of the Natural Gas Act exempts natural gas gathering facilities from the jurisdiction of the FERC. Atlas owns a number of intrastate natural gaspipelines in New York, Pennsylvania, Ohio, Arkansas, Texas and Oklahoma that Atlas believes would meet the traditional tests FERC has used to establish apipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between the FERC−regulated transmission services and federallyunregulated gathering services is the subject of regular litigation, so the classification and regulation of some of Atlas’ gathering facilities may be subject tochange based on future determinations by FERC and the courts.

In Ohio, a producer or gatherer of natural gas may file an application seeking exemption from regulation as a public utility, except for the continuing jurisdictionof the Public Utilities Commission of Ohio to inspect its gathering systems for public safety purposes. Atlas’ operating subsidiary has been granted an exemptionby the Public Utilities Commission of Ohio for its Ohio facilities. The New York Public Service Commission imposes traditional public utility regulation on thetransportation of natural gas by companies subject to its regulation. This regulation includes rates, services and siting authority for the construction of certainfacilities. Atlas’ gas gathering operations currently are not subject to regulation by the New York Public Service Commission. Atlas’ operations in Pennsylvaniacurrently are not subject to the Pennsylvania Public Utility Commission’s regulatory authority since they do not provide service to the public generally and,accordingly, do not constitute the operation of a public utility. Similarly, Atlas’ operations in Arkansas are not subject to regulatory oversight by the ArkansasPublic Service Commission. In the event the Arkansas, Ohio, New York or Pennsylvania authorities seek to regulate our operations, Atlas believes that itsoperating costs could increase and Atlas’ transportation fees could be adversely affected, thereby reducing Atlas’ net revenue and ability to make distributions tounitholders.

Atlas is currently subject to state ratable take and common purchaser statutes in Texas and Oklahoma. The ratable take statutes generally require gatherers totake, without discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally requiregatherers to purchase without discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producerover another producer or one source of supply over another source of supply. These statutes have the effect of restricting Atlas’ right as an owner of gatheringfacilities to decide with whom it contracts to purchase or transport natural gas.

The state of Oklahoma has adopted a complaint−based statute that allows the Oklahoma Corporation Commission to resolve grievances relating to natural gasgathering access and to remedy discriminatory rates for providing gathering service where the parties are unable to agree. In a similar way, the Texas RailroadCommission sponsors a complaint procedure for resolving grievances about natural gas gathering access and rate discrimination. No such complaints have beenmade against Atlas’ Mid−Continent operations to date in Oklahoma or Texas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulationof the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulatedaffiliates. For example, the Texas Railroad Commission has approved changes to its regulations governing transportation and gathering services performed byintrastate pipelines and gatherers, which prohibit such

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entities from unduly discriminating in favor of one customer over another. Atlas’ gathering operations could be adversely affected should they be subject in thefuture to the application of state or federal regulation of rates and services.

Atlas’ gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction,operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time totime. Atlas cannot predict what effect, if any, such changes might have on its operations, but the industry could be required to incur additional capitalexpenditures and increased costs depending on future legislative and regulatory changes.

Sales of Natural GasA portion of Atlas’ revenue is tied to the price of natural gas. The price of natural gas is not currently subject to federal regulation and, for the most part, is notsubject to state regulation. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms ofaccess to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulationsaffecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC’s jurisdiction. Theseinitiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is topromote competition among the various sectors of the natural gas industry, and these initiatives generally reflect more light−handed regulation. Atlas cannotpredict the ultimate impact of these regulatory changes to its operations, and we note that some of FERC’s more recent proposals may adversely affect theavailability and reliability of interruptible transportation service on interstate pipelines. Atlas does not believe that it will be affected by any such FERC actionmaterially differently than other companies with whom it competes.

Energy Policy Act of 2005On August 8, 2005, the Energy Policy Act of 2005 was signed into law. The Energy Policy Act contains numerous provisions relevant to the natural gas industryand to interstate pipelines in particular. Overall, the legislation attempts to increase supply sources by engaging in various studies of the overall resource base andattempting to advantage deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the primary provisions of interest to Atlas’interstate pipelines focus in two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement. Regarding infrastructuredevelopment, the Energy Policy Act includes provisions to clarify that FERC has exclusive jurisdiction over the siting of liquefied natural gas terminals; providesfor market based rates for new storage facilities placed into service after the date of enactment; shortens depreciable life for gathering facilities; statutorilydesignates FERC as the lead agency for federal authorizations and permits; creates a consolidated record for all federal decisions relating to necessaryauthorizations and permits; and provides for expedited judicial review of any agency action and review by only the D.C. Circuit Court of Appeals of any allegedfailure of a federal agency to act by a deadline set by FERC as lead agency. Such provisions, however, do not apply to review and authorization under the CoastalZone Management Act of 1972. Regarding market transparency and manipulation rules, the Natural Gas Act is amended to prohibit market manipulation and addprovisions for FERC to prescribe rules designed to encourage the public provision of data and reports regarding the price of natural gas in wholesale markets.The Natural Gas Act and the Natural Gas Policy Act are also amended to increase monetary criminal penalties to $1,000,000 from current law at $5,000 and toadd and increase civil penalty authority to be administered by FERC to $1,000,000 per day per violation without any limitation as to total amount.

Environmental MattersThe operation of pipelines, plant and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids and otherproducts is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities,Atlas must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact Atlas’ businessactivities in many ways, such as:

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• restricting the way Atlas can handle or dispose of its wastes;

• limiting or prohibiting construction and operating activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangeredspecies;

• requiring remedial action to mitigate pollution conditions caused by its operations or attributable to former operators; and

• enjoining some or all of the operations of facilities deemed in non−compliance with permits issued pursuant to such environmental laws andregulations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedialrequirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required toclean up and restore sites where substances or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners andother third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

Atlas believes that its operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal,state and local environmental laws and regulations will not have a material adverse effect on Atlas’ business, financial position or results of operations.Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, therecan be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may bedifferent from the amounts Atlas currently anticipates. Moreover, Atlas cannot assure you that future events, such as changes in existing laws, the promulgationof new laws, or the development or discovery of new facts or conditions will not cause Atlas to incur significant costs.

Hazardous WasteAtlas’ operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, as amended, orRCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRAcurrently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from thedefinition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas.However, these oil and gas exploration and production wastes may still be regulated under state law or the less stringent solid waste requirements of RCRA.Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste.The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

Site RemediationThe Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, also known as “Superfund,” and comparablestate laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardoussubstances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, andcompanies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum as well as natural gas isexcluded from CERCLA’s definition of “hazardous substance,” in the course of Atlas’ ordinary operations it will generate wastes that may fall within thedefinition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health orthe environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, Atlas could be subject to joint and several,strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costsof certain health studies.

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Atlas currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering,field compression and processing of natural gas. Although Atlas used operating and disposal practices that were standard in the industry at the time, petroleumhydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by Atlas or on or under other locations where suchsubstances have been taken for disposal. In fact, there is evidence that petroleum spills or releases have occurred at some of the properties owned or leased byAtlas. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release of petroleumhydrocarbons or wastes was not under Atlas’ control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA andanalogous state laws. Under such laws, Atlas could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators),remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or performremedial closure operations to prevent future contamination.

Air EmissionsAtlas’ operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations regulate emissionsof air pollutants from various industrial sources, including processing plants and compressor stations, and also impose various monitoring and reportingrequirements. Such laws and regulations may require that Atlas obtain pre−approval for the construction or modification of certain projects or facilities expectedto produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions andoperational limitations, or utilize specific emission control technologies to limit emissions. Atlas’ failure to comply with these requirements could subject Atlasto monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Atlas likely will be required to incurcertain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for airemissions. Atlas believes, however, that its operations will not be materially adversely affected by such requirements, and the requirements are not expected to beany more burdensome to Atlas than to any other similarly situated companies.

Water DischargesAtlas’ operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws andregulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. Thedischarge of pollutants is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder alsoprohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Anyunpermitted release of pollutants from Atlas’ pipelines or facilities could result in administrative, civil and criminal penalties as well as significant remedialobligations.

Pipeline SafetyAtlas’ pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended,or the NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement andmanagement of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases, and the transportation and storage of liquefiednatural gas and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allowcopying of records and to make certain reports and provide information as required by the Secretary of Transportation. Atlas believes that its pipeline operationsare in substantial compliance with existing NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation ofexisting laws and regulations, future compliance with the NGPSA could result in increased costs.

The DOT, through the Office of Pipeline Safety, recently finalized a series of rules intended to require pipeline operators to develop integrity managementprograms for gas transmission pipelines that, in the event

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of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildingscontaining populations of limited mobility, and areas where people gather that are located along the route of a pipeline. The Texas Railroad Commission, theOklahoma Corporation Commission and other state agencies have adopted similar regulations applicable to intrastate gathering and transmission lines.Compliance with these existing rules has not had a material adverse effect on Atlas’ operations but there is no assurance that this trend will continue in the future.

Employee Health and Safety

Atlas is subject to the requirements of the Occupational Safety and Health Act, as amended, referred to as OSHA, and comparable state laws that regulate theprotection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardousmaterials used or produced in Atlas’ operations and that this information be provided to employees, state and local government authorities and citizens.

Hydrogen SulfideExposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans, and prolonged exposure can result in death. The gasproduced at Atlas’ Velma gas plant contains high levels of hydrogen sulfide, and Atlas employs numerous safety precautions at the system to ensure the safety ofAtlas’ employees. There are various federal and state environmental and safety requirements for handling sour gas, and Atlas is in substantial compliance with allsuch requirements.

EmployeesAs is commonly the case with publicly traded limited partnerships, Atlas does not directly employ any of the persons responsible for Atlas’ management oroperations. In general, employees of Atlas America manage Atlas’ gathering systems and operate Atlas’ business. Our affiliates will conduct business andactivities of their own in which Atlas will have no economic interest. If these separate activities are significantly greater than Atlas’ activities, there could bematerial competition between them, us and our affiliates for the time and effort of the officers and employees who provide services to us. Our officers whoprovide services to Atlas are not required to work full time on Atlas’ affairs. These officers may devote significant time to the affairs of our affiliates and becompensated by these affiliates for the services rendered to them. There may be significant conflicts between them and our affiliates regarding the availability ofthese officers to manage them.

PropertiesAs of December 31, 2004, Atlas’ principal facilities in Appalachia include approximately 1,500 miles of 2 to 12 inch diameter pipeline. Atlas’ principal facilitiesin the Mid−Continent area consist of three natural gas processing plants, one treating facility, and approximately 3,130 miles of active and inactive 2−to−42 inchdiameter pipeline. Substantially all of Atlas’ gathering systems are constructed within rights−of−way granted by property owners named in the appropriate landrecords. In a few cases, property for gathering system purposes was purchased in fee. All of Atlas’ compressor stations are located on property owned in fee oron property obtained via long−term leases or surface easements.

Atlas’ property or rights−of−way are subject to encumbrances, restrictions and other imperfections, although these imperfections have not interfered, and Atlas’general partner does not expect that they will materially interfere with the conduct of Atlas’ business. In many instances, lands over which rights−of−way havebeen obtained are subject to prior liens which have not been subordinated to the right−of−way grants. In a few instances, Atlas’ rights−of−way are revocable atthe election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the right−of−way grants, but insubstantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authoritiesto cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary, although in someinstances these permits are revocable at the election of the grantor. Substantially all permits have also been

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obtained from railroad companies to cross over or under lands or rights−of−way, many of which are also revocable at the grantor’s election.

Certain of Atlas’ rights to lay and maintain pipelines are derived from recorded gas well leases, for wells that are currently in production; however, the leases aresubject to termination if the wells cease to produce. In some of these cases, the right to maintain existing pipelines continues in perpetuity, even if the wellassociated with the lease ceases to be productive. In addition, because many of these leases affect wells at the end of lines, these rights−of−way will not be usedfor any other purpose once the related wells cease to produce.

Atlas rents 24,959 square feet of office space through November 2009 in Tulsa, Oklahoma for its Mid−Continent operations. For a description of Atlas’ naturalgas processing plants, see “—Our Mid−Continent Operations—Processing Plants.”

Legal ProceedingsOn March 9, 2004, the Oklahoma Tax Commission filed a petition against Spectrum alleging that Spectrum underpaid gross production taxes beginning in June2000. The OTC is seeking a settlement of $5.0 million plus interest and penalties. Atlas plans on defending itself vigorously. Atlas has asserted a claim forindemnification by Chevron under the provisions of Atlas’ contract with it. Chevron has acknowledged Atlas’ claim notice pursuant to which Chevron will beresponsible for the payment of any underpayment of taxes, which would be the basis for any monetary judgment against them, but Chevron will reserve theissues of payment of penalties and reimbursement of Atlas’ attorneys fees and costs for determination by arbitration following the end of the litigation. Inaddition, under the terms of the Spectrum purchase agreement, $14.0 million has been placed in escrow to cover the costs of any adverse settlement resultingfrom the petition and other indemnification obligations of the purchase agreement.

Atlas is not subject to any other pending legal proceedings.

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MANAGEMENT


Directors and Officers of Atlas Pipeline Holdings GP, LLC

The following table sets forth certain information with respect to the executive officers and members of the board of directors of our general partner, AtlasPipeline Holdings GP, LLC. Executive officers and directors will serve until their successors are duly appointed or elected.

Name AgePosition with general

partner

Edward E. Cohen 66 Chairman of theBoard and ChiefExecutive Officer

Jonathan Z. Cohen 35 Vice Chairman ofthe Board

Robert R. Firth 51 President Matthew A. Jones 44 Chief Financial

Officer Lisa Washington 38 Chief Legal

Officer andSecretary

Steven J. Doherty 45 Director William G. Karis 57 Director Harvey G. Magarick 66 Director

Edward E. Cohen has been the Chairman of the Board of Directors and Chief Executive Officer of our general partner since its formation in January 2006. Mr.Cohen also has been Chairman of the Board of Directors and Chief Executive Officer of Atlas America since its formation in 2000 and of Atlas since itsformation in 1999. Mr. Cohen has been Chairman of the Board of Directors of Resource America, Inc. (NASDAQ: REXI), since 1990, and a director since 1988.Mr. Cohen served as Chief Executive Officer of Resource America from 1988 to 2004 and President of Resource America from 2000 to 2003. He is Chairman ofthe Board of Directors of Brandywine Construction & Management, Inc., a property management company, and a director of TRM Corporation, a publicly tradedconsumer services company, Mr. Cohen is the father of Jonathan Z. Cohen.

Jonathan Z. Cohen has been the Vice Chairman of the Board of Directors of our general partner since January 2006. Mr. Cohen also has been the President ofResource America since 2003, Chief Executive Officer of Resource America since 2004 and a director since 2002. He was the Chief Operating Officer ofResource America from 2002 to 2004 and Executive Vice President of Resource America from 2001 until 2003. Before that, Mr. Cohen had been a Senior VicePresident since 1999. Mr. Cohen has been Vice Chairman of Atlas America since its formation in 2000 and Vice Chairman of Atlas since its formation in 1999.Mr. Cohen has also served as Trustee and Secretary of RAIT Investment Trust, a publicly−traded real estate investment trust, since 1997, Vice Chairman ofRAIT since 2003 and Chairman of the Board of Directors of The Richardson Company, a sales consulting company, since 1999. Mr. Cohen is a son of EdwardE. Cohen.

Robert R. Firth has been the President of our general partner since January 2006. Mr. Firth also has been the President and Chief Executive Officer of Spectrum(acquired by Atlas in July 2004 and now known as Atlas Pipeline Mid−Continent LLC) since 2002. Mr. Firth has held positions with Northern Natural Gas,Panda Resources, Transok, CMS Energy and ScissorTail Energy over his 30 years in the midstream energy sector.

Matthew A. Jones has been the Chief Financial Officer of our general partner since January 2006. Mr. Jones also has been Chief Financial Officer of Atlas andAtlas America since March 2005. Prior to that time, Mr. Jones was a Managing Director with the Energy Investment Banking Group at Friedman BillingsRamsey. Before that, Mr. Jones had been associated with Friedman Billings Ramsey’s Specialty Finance and Real Estate Group. Mr. Jones is a CharteredFinancial Analyst.

Lisa Washington has been the Chief Legal Officer and Secretary of our general partner since January 2006. Ms. Washington is also the Vice President, ChiefLegal Officer and Secretary of Atlas and Atlas America. From 1999 to 2005, Ms. Washington was an attorney in the business department of the law firm ofBlank Rome LLP.

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Steven J. Doherty has been a member of the Board of Directors of our general partner since January 2006. Mr. Doherty, a Chartered Financial Analyst, has beena Vice President and Client Portfolio Manager of Loomis Sayles & Co., since 1996 and was a Vice President and Portfolio Manager of Loomis Sayles between1996 and 1999. From 1986 to 1996, Mr. Doherty was a Senior Portfolio Manager of Howard Hughes Medical Institute. Mr. Doherty is on the Board of Advisorsof the George Washington University School of Business and Public Management.

William G. Karis has been a member of the Board of Directors of our general partner since January 2006 and has been the principal of Karis and Associates,LLC, a consulting company that provides financial and consulting services to the coal industry, since 1997. Prior to that, Mr. Karis was President and CEO ofCONSOL Inc. (now CONSOL Energy Company). Mr. Karis is a member of the Boards of Directors and is Chairman of the Audit and Finance Committees ofBlue Danube Inc., PinnOak Resources, LLC (formerly US Steel Mining), and Greenbriar Minerals, LLC.

Harvey G. Magarick has been a member of the Board of Directors of our general partner since January 2006 and has maintained his own consulting practicesince June 2004. From 1997 to 2004, Mr. Magarick was a partner at BDO Seidman. Mr. Magarick is a member of the Board of Trustees of the Hirtle CallaghanTrust, an investment fund, and has been the Chairman of its audit committee since 2004.

Other Significant EmployeesSean P. McGrath, 34, has been the Chief Accounting Officer of our general partner since January 2006. Mr. McGrath also has been the Chief AccountingOfficer of Atlas since May 2005. Before that, Mr. McGrath had been the Chief Accounting Officer of Sunoco Logistics Partners L.P., a publicly−tradedpartnership that transports, terminals and stores refined products and crude oil, since 2002. From 1998 to 2002, Mr. McGrath was Assistant Controller ofAsplundh Tree Expert Co., a utility services and vegetation management company.

Daniel C. Herz, 29, has been the Vice President of Corporate Development of our general partner since January 2006. Mr. Herz also has been an employee ofAtlas and Atlas America since January 2004 and has served as Vice President of Corporate Development since December 2004. Mr. Herz was an AssociateInvestment Banker with Banc of America Securities from 2002 to 2003 and an Analyst from 1999 to 2002.

Board Committees

Audit CommitteeOur general partner’s board of directors will establish an audit committee to be effective upon the closing of this offering. The three independent members of ourgeneral partner’s board of directors will serve on the audit committee that will review our external financial reporting, maintain responsibility for engaging ourindependent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. In addition to satisfying certain otherrequirements, the members of the audit committee must meet the independence standards for an audit committee of a board of directors established by the NYSE.Upon completion of this offering, Messrs. Doherty, Karis and Magarick will be the members of the Audit Committee.

Conflicts CommitteeOur general partner’s board of directors will establish a conflicts committee to be effective upon the closing of this offering. Ultimately, at least two members ofour general partner’s board of directors will serve on the conflicts committee, which will be charged with reviewing specific matters that our general partner’sboard of directors believes may involve conflicts of interest. The conflicts committee will determine if the resolution of any conflict of interest submitted to it isfair and reasonable to us. In addition to satisfying certain other requirements, the members of the conflicts committee must meet the independence standards for aconflicts committee of a board of directors established by the NYSE. Any matters approved by the conflicts committee will be conclusively deemed to be fairand reasonable to us, approved by all of our unitholders, and not a breach by us of any duties we may owe to our unitholders.

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Compensation Committee

Our general partner’s board of directors will establish a compensation committee of at least two directors to be effective upon the closing of this offering. Thecompensation committee will oversee compensation decisions and benefits for the officers of our general partner and will administer our Long−Term IncentivePlan described below.

Compensation for the officers of our general partner shall be determined by the independent directors constituting the compensation committee of Atlas America,the sole shareholder of our general partner and the employer of all of the officers. Charges to us (and hence indirectly compensation of officers attributable to,and payable by, us) will be cleared with the conflicts committee of the board of directors of our general partner.

Executive CommitteeOur general partner’s board of directors will establish an executive committee of four directors to be effective upon the closing of this offering. The role of theexecutive committee, which will be chaired by the Vice Chairman of the Board of our general partner, is to exercise all powers of our general partner’s board ofdirectors between board meetings when it is not practical or feasible for the full board to meet. Upon completion of this offering, Messrs. Edward E. Cohen,Jonathan Z. Cohen, Robert R. Firth and Matthew A. Jones will be the members of the Executive Committee.

Other CommitteesOur general partner’s board of directors may establish other committees from time to time to facilitate our management.

Election of Our DirectorsOur general partner’s limited liability company agreement establishes a board of directors that will be responsible for the oversight of our business andoperations. Our general partner’s board of directors will be elected by a voting majority, as defined in the limited liability company agreement.

Governance MattersIndependence of Board Members. Our general partner is committed to having at least three independent directors on its board of directors. Pursuant to theNYSE listing standards, a director will be considered independent if the board determines that he or she does not have a material relationship with our generalpartner or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with our general partner or us). The initialindependent directors are Steven J. Doherty, William G. Karis and Harvey G. Magarick. The independent members of the board of directors of our generalpartner will serve as the initial members of the audit and conflicts and compensation committees.

Heightened Independence for Audit and Conflicts Committee Members. As required by the Sarbanes−Oxley Act of 2002, the Commission has adopted rulesthat direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfya heightened independence standard. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or othercompensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the publiccompany. The board of directors of our general partner expects that all members of its audit and conflicts committee will satisfy this heightened independencerequirement.

Audit Committee Financial Expert. An audit committee plays an important role in promoting effective corporate governance, and it is imperative that membersof an audit committee have requisite financial literacy and expertise. As required by the Sarbanes−Oxley Act of 2002, Commission rules require that a publiccompany disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined asa person who, based on his or her experience, possesses all of the following attributes:

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• An understanding of generally accepted accounting principles and financial statements;

• An ability to assess the general application of such principles in connection with the accounting for estimates, accruals, and reserves;

• Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that aregenerally comparable to the breadth and level of complexity of issues that can reasonably be expected to be raised by our financial statements, orexperience actively supervising one or more persons engaged in such activities;

• An understanding of internal controls and procedures for financial reporting; and

• An understanding of audit committee functions.

The board of directors of our general partner expects that one of the independent directors will satisfy the definition of “audit committee financial expert.”

Code of Ethics. The board of directors of our general partner will adopt a code of ethics, the “Code of Ethical Conduct for Senior Financial Officers andManagers,” that applies to the chief executive officer, chief financial officer, principal accounting officer and senior financial and other managers. In addition toother matters, this code of ethics will establish policies to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actualand apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in publiccommunications and prompt internal reporting violations of the code.

Web Access. We will provide access through our website to current information relating to governance, including a copy of the Code of Ethical Conduct forSenior Financial Officers and Managers and other matters impacting our governance principles. You will be able to contact our investor relations department forpaper copies of these documents free of charge.

Compensation of DirectorsOur general partner does not contemplate paying additional remuneration to officers or employees of Atlas America who also serve on the board of directors ofour general partner. Each non−employee director will receive an annual retainer of $35,000 in cash and an annual grant of phantom units with distributionequivalent rights in an amount equal to the lesser of 500 units or $15,000 worth of units (based upon the market price of our common units) pursuant to ourLong−Term Incentive Plan. Please see “—Atlas Pipeline Holdings Long−Term Incentive Plan” below. In addition, our general partner will reimburse eachnon−employee director for out−of−pocket expenses and indemnify our general partner’s board of directors for actions associated with serving as directors to theextent permitted under Delaware law.

Atlas Pipeline Holdings Long−Term Incentive PlanPrior to the closing of this offering, we will adopt the Atlas Pipeline Holdings, L.P. Long−Term Incentive Plan for the employees, directors and consultants ofour general partner and its affiliates, including Atlas, who perform services for us. The long−term incentive plan will consist of phantom units, unit options andtandem distribution equivalent rights with respect to phantom units. Units with respect to awards forfeited, terminated or paid without the delivery of units areavailable for delivery pursuant to other awards. The long−term incentive plan will be administered by the compensation committee of the board of directors ofour general partner.

The board of directors of our general partner and the compensation committee of the board may terminate or amend the long−term incentive plan at any timewith respect to any units for which a grant has not yet been made. Our board of directors and the compensation committee of the board also have the right to alteror amend the long−term incentive plan or any part of the long−term incentive plan from time to time, including increasing the number of units that may begranted, subject to unitholder approval as may be required by the exchange upon which the common units are listed at that time, if any. Subject to adjustment asprovided in the long−term incentive plan documents, the aggregate number of our units that may be awarded to participants is 2,100,000. However, no change inany outstanding grant may be made that would

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materially reduce the benefits of the participant without the consent of the participant. The long−term incentive plan will expire upon its termination by the boardof directors or the compensation committee or, if earlier, when no units remain available under the long−term incentive plan for awards. Upon termination of thelong−term incentive plan, awards then outstanding will continue pursuant to the terms of their grants.

Phantom Units. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensationcommittee, cash equivalent to the value of a common unit. In the future, the compensation committee may determine to make grants of phantom units under theplan to employees, consultants and directors containing such terms as the compensation committee determines. The compensation committee will determine theperiod over which phantom units granted to employees and members of our board will vest. The committee, in its discretion, may base its determination upon theachievement of specified financial objectives or other events. In addition, the phantom units will vest upon a change in control. If a grantee’s employment,consulting or membership on the board of directors terminates for any reason, the grantee’s phantom units will be automatically forfeited unless, and to theextent, the compensation committee or the terms of the award agreement provide otherwise.

Options. An option entitles the grantee to receive a common unit upon payment of the exercise price for the option, which exercise price may be equal to ormore than the fair market value of a common unit on the date of grant of the option. The compensation committee will determine the directors, employees andconsultants to whom options are granted, the number of options, their vesting provisions, exercise price and other terms and conditions.

Common units to be delivered upon the vesting of phantom units or the exercise of options may be common units acquired by us in the open market, commonunits acquired by us from any other person or any combination of the foregoing. If we issue new common units upon vesting of the phantom units or the exerciseof options, the total number of common units outstanding will increase.

We intend that the issuance of any common units upon vesting of the phantom units under the plan serve as a means of incentive compensation for performanceand not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not pay any consideration forthe common units they receive, and we will receive no remuneration for the units.

U.S. Federal Income Tax Consequences of Awards Under the Long−Term Incentive Plan. Generally, when phantom units or options are granted, there are noincome tax consequences for the participant or us. Upon the payment to the participant of common units and/or cash in respect of the vesting of phantom units orDERs or the exercise of units, the participant recognizes compensation equal to the fair market value of the cash and/or units as of the date of payment.

On October 22, 2004, the American Jobs Creation Act of 2004 (H.R. 4520) (the “AJCA”) was signed into law by the President. The AJCA added a new Section409A to the Internal Revenue Code (“Section 409A”) which significantly alters the rules relating to the taxation of deferred compensation. Section 409A broadlyapplies to deferred compensation and potentially results in additional tax to participants. The Department of Treasury and IRS have issued guidance and proposedregulations under Section 409A, however further guidance is anticipated. Based on current guidance, the award of options to employees, consultants anddirectors of certain of our affiliates may be very limited in order to meet the requirements of Section 409A. However, we expect that we will be able to structureawards under the plan in a manner that complies with Section 409A. Because we expect additional guidance to be issued under Section 409A, we may berequired to alter provisions of the plan and future awards.

DERs. A distribution equivalent right or DER is a right granted in the committee’s discretion with respect to a phantom unit that entitles the grantee to receivecash equal to the cash distributed on a common unit on such terms and conditions as the committee may proscribe.

Compensation Committee Interlocks and Insider ParticipationWhile certain of our executive officers and directors serve in such roles with Atlas America and the general partner of Atlas, none of our executive officers servesas a member of the board of directors or

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compensation committee of any entity that has one or more of its executive officers serving as a member of the board of directors or compensation committee ofour general partner.


Managing Board Members, Executive Officers and Other Significant Employers of Atlas Pipeline Partners

The following table sets forth certain information with respect to the executive officers and members of the managing board of Atlas Pipeline Partners GP, LLC.Executive officers and directors will serve until their successors are duly appointed or elected.

Name Age Position with general partnerYear in whichservice began

Edward E. Cohen 66 Chairman of the Managing Boardand Chief Executive Officer

1999

Jonathan Z. Cohen 35 Vice Chairman of the ManagingBoard

1999

Michael L. Staines 56 President, Chief Operating Officerand Managing Board Member

1999

Matthew A. Jones 44 Chief Financial Officer 2005Tony C. Banks 51 Managing Board Member 1999Curtis D. Clifford 63 Managing Board Member 2004Gayle P.W. Jackson 59 Managing Board Member 2005Martin Rudolph 59 Managing Board Member 2005

As described above, some of the managing board members, executive officers and other significant employees of our general partner, Atlas Pipeline HoldingsGP, LLC, also serve as directors, executive officers and other significant employees of Atlas’ general partner. To the extent that we have described the businessexperience of these individuals above, we have not repeated that information below.

Michael L. Staines has been an Executive Vice President of Atlas America since its formation. Mr. Staines is also the President and Chief Operating Officer ofAtlas. Mr. Staines was Senior Vice President of Resource America from 1989 to 2004 and served as a director from 1989 through 2000 and Secretary from 1989through 1998. Mr. Staines is a member of the Ohio Oil and Gas Association, the Independent Oil and Gas Association of New York and the IndependentPetroleum Association of America.

Tony C. Banks is a Vice President of First Energy Solutions, Inc., a subsidiary of First Energy Corp., a public utility, since 2005. Mr. Banks is responsible forunregulated sales of electricity and energy−related products and services. Mr. Banks was previously the Director of Marketing for First Energy Solutions. Beforethat, Mr. Banks was a consultant to utilities, energy service companies and energy technology firms. From 2000 through 2002, Mr. Banks was President of RAIVentures, Inc. and Chairman of the Board of Optiron Corporation, which was an energy technology subsidiary of Atlas America until 2002. In addition, Mr.Banks served as President of our general partner during 2000. He was Chief Executive Officer and President of Atlas America from 1998 through 2000.

Curtis D. Clifford has been the principal of CL4D CO, an energy consulting, marketing and reporting firm since 1998. Mr. Clifford has 39 years’ experience inthe natural gas industry, from exploration, production and gathering to procurement, marketing and consulting. He has been president of Amity Manor, Inc. since1988 when he founded the company to develop housing for low−income elderly using tax credit financing. Mr. Clifford is a registered professional engineer inPennsylvania.

Gayle P.W. Jackson has been President of Energy Global, Inc., a consulting firm which specializes in corporate development, diversification and governmentrelations strategies for energy companies, since 2004. From 2001 to 2004, Dr. Jackson served as Managing Director of FE Clean Energy Group, a global privateequity management firm that invests in energy companies and projects in Central and Eastern Europe, Latin America and Asia. From 1985 to 2001, Dr. Jacksonwas President of Gayle P.W. Jackson, Inc., a consulting firm that advised energy companies on corporate development and diversification strategies and alsoadvised national and international governmental institutions on energy policy. Dr. Jackson has been Deputy Chairman

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of the Federal Reserve Bank of St. Louis since 2003 and a Board member since 2000, and is a member of the Board of Directors of Ameren Corporation, apublicly−traded public utility holding company.

Martin Rudolph has been the Trustee of the AHP Settlement Trust, a $5 billion trust established to process litigation claims, since 2005. Before that, Mr.Rudolph was the director of tax planning, research and compliance for RSM McGladrey, Inc., a business services firm from 2001 to 2005. From 1990 to 2001, hewas a Managing Partner of Rudolph, Palitz LLC, which was merged with RSM McGladrey. Mr. Rudolph is a certified public accountant.

Other Significant EmployeesDavid D. Hall, 48, has been the Executive Vice President and Chief Financial Officer of Spectrum (acquired by Atlas in July 2004 and now known as AtlasPipeline Mid−Continent LLC) since 2002. From 2000 to 2002, Mr. Hall served as a senior business analyst at ScissorTail Energy. Mr. Hall has more than 25years experience as a financial executive in the energy industry.

Messrs. Firth, McGrath and Herz and Ms. Washington also are significant employees of Atlas Pipeline Partners GP, LLC.

Reimbursement of Expenses of Atlas’ General Partner and its AffiliatesAtlas does not directly employ any persons to manage or operate its business. These functions are provided by Atlas’ general partner and employees of AtlasAmerica. Atlas’ general partner does not receive a management fee in connection with its management of Atlas apart from its interest as general partner and itsright to receive incentive distributions.

Atlas reimburses its general partner and its affiliates for compensation and benefits related to their executive officers, based upon an estimate of the time spent bysuch persons on activities for Atlas. Other indirect costs, such as rent for offices, are allocated to Atlas by Atlas America based on the number of Atlas Americaemployees who devote substantially all of their time to activities on Atlas’ behalf. Atlas reimburses Atlas America at cost for direct costs incurred by them onAtlas’ behalf.

Atlas’ partnership agreement provides that its general partner will determine the costs and expenses that are allocable to Atlas in any reasonable mannerdetermined by its general partner at its sole discretion. Atlas reimbursed its general partner and its affiliates $0.7 million and $1.4 million for the nine monthsended September 30, 2004 and 2005, respectively, for compensation and benefits related to its executive officers. Direct reimbursements were $7.2 million and$17.1 million for the nine months ended September 30, 2004 and 2005, respectively, including certain costs that have been capitalized by Atlas. Atlas’ generalpartner believes that the method utilized in allocating costs to Atlas is reasonable.

Executive Officer CompensationThe following table sets forth certain compensation information for the chief executive officer and each of the four other most highly compensated executiveofficers of Atlas’ general partner in excess of $100,000 for 2004, 2003 and 2002. Atlas reimburses Atlas’ general partner and its affiliates for expenses incurredon Atlas’ behalf, including the cost of officer compensation allocable to Atlas. It is not currently anticipated that Atlas will pay additional annual cash or cashbonus compensation to the officers of our general partner for service to us, but that such officers will be compensated through the Long−Term Incentive Plan weare adopting concurrently with this offering.

Summary Compensation Table

Annual Compensation

All OtherName and Principal Position Year Salary Bonus Compensation(1)

Edward E. CohenChairman of the Managing Boardand Chief Executive Officer

200420032002

$$$

133,950179,600

0

$$$

193,800119,700

0

$ 931,500

Michael L. Staines 2004 $ 219,400 $ 45,600 $ 298,080President, Chief Operating Officer 2003 $ 133,300 $ 10,000and Managing Board Member 2002 $ 169,979 $ 28,000

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(1) Reflects grants of phantom units under the Atlas Long Term Incentive Plan, valued at the closing price of common units on the respective dates of grants.The phantom unit grants entitle the recipient, upon vesting, to receive one common unit or its then fair market value in cash and include distributionequivalent rights. The number of phantom units held and the value of those phantom units, valued at the closing market price of Atlas common units onDecember 31, 2004, are: Mr. E. Cohen — 25,000 phantom units ($1,047,500) and Mr. Staines — 8,000 phantom units ($335,200).

Long−Term Incentive Plan

Atlas’ general partner has adopted the Atlas Pipeline Partners, L.P. Long−Term Incentive Plan, referred to as the Plan, for employees of Atlas’ general partnerand its affiliates who perform services for Atlas. Awards contemplated by the Plan include phantom units and unit options. The Plan currently permits the grantof phantom units and unit options covering an aggregate of 435,000 common units delivered upon vesting of such phantom units or unit options. The Plan isadministered by a committee appointed by Atlas’ general partner’s managing board, which sets the terms of awards under the Plan. This committee may makeawards of either phantom units or options for an aggregate of 435,000 common units, provided that the maximum number of phantom units that may be awardedin total to non−employee managing board members is 10,000.

Phantom Units. A phantom unit entitles the grantee to receive, upon the vesting of the phantom unit, a common unit (or cash equivalent, depending on theterms of the grant). As of December 31, 2004, grants of 58,752 unvested phantom units under the Plan remain outstanding to employees, officers and directors ofAtlas’ general partner. This committee may, in the future, make additional grants under the plan to employees and directors containing such terms as suchcommittee shall determine, including tandem distribution equivalent rights with respect to phantom units. As a result of the vesting of these awards, Atlasrecognized an expense of $0.7 million during 2004.

The issuance of the common units upon vesting of phantom units is primarily intended to serve as a means of incentive compensation for performance.Therefore, no consideration is paid to Atlas by the plan participants upon receipt of the common units.

Grants of 1,752 phantom units were made in 2004 to current non−employee directors of Atlas’ general partner. These units vest and are payable in 25%increments.

The following table shows the vesting of phantom units granted under the Plan during 2004 to the named executive officers.

Remaining UnvestedGrants(1)

Name Total Units Units Value

Edward E. Cohen 25,000 25,000 $ 1,047,500Michael L. Staines 8,000 8,000 $ 335,200

(1) As if vested on December 31, 2004, at a market closing price of $41.90 per unit.

Compensation of Managing Board Members

Atlas’ general partner does not pay additional remuneration to officers or employees of Atlas America who also serve as managing board members. In fiscal year2004, each non−employee managing board member of Atlas’ general partner received an annual retainer of $20,000 in cash and an annual grant of phantom unitswith DERs in an amount equal to the lesser of 500 units or $15,000 worth of units (based upon the market price of our common units) pursuant to Atlas’Long−Term Incentive Plan, which was approved by Atlas’ unitholders on February 11, 2004. In addition, Atlas’ general partner reimburses each non−employeeboard member for out−of−pocket expenses in connection with attending meetings of the board or committees. Atlas reimburses its general partner for theseexpenses and indemnifies its general partner’s managing board members for actions associated with serving as managing board members to the extent permittedunder Delaware law.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT


The following table sets forth certain information regarding the beneficial ownership of our common units prior to and as of the closing of this offering by:

• each person who will beneficially own more than 5% of our common units;

• each of the named executive officers of our general partner;

• all of the directors of our general partner; and

• all directors and executive officers of our general partner as a group.All information with respect to beneficial ownership has been furnished by the respective directors or officers, as the case may be.

Common Units Beneficially OwnedAfter Offering

Name of Beneficial Owner Common Units Percent

Atlas America, Inc.AIC, Inc.Viking Resources CorporationResource Energy, Inc.REI−NY, Inc.Edward E. CohenJonathan Z. CohenRobert R. FirthMatthew A. JonesLisa WashingtonSteven J. DohertyWilliam G. KarisHarvey G. MagarickAll directors and officers of our general partner as a group (8 persons)

* Less than 1%.


The following table sets forth certain information as of December 31, 2005 regarding beneficial ownership of Atlas’ common units by:

• each person known by Atlas Pipeline GP to beneficially own more than 5% of Atlas’ common units;

• each of the named executive officers of Atlas Pipeline GP;

• all of the directors of Atlas Pipeline GP;

• all of the directors and executive officers of Atlas Pipeline GP as a group.All information with respect to beneficial ownership has been furnished by the respective directors or officers, as the case may be. Each person has sole votingand dispositive power over the common units shown unless otherwise indicated below. Atlas has 12,549,266 common units outstanding at December 31, 2005.

Common Units Beneficially OwnedAfter Offering

Name of Beneficial Owner Common Units Percent

Atlas Pipeline GP 1,641,026 12.8%Edward E. Cohen 10,350 *Jonathan Z. Cohen 7,727 *Michael L. Staines 2,000 *Matthew A. Jones 0 *Tony C. Banks (a) 195 *Curtis D. Clifford 113 *Gayle P.W. Jackson 0 *Martin Rudolph 500 *All directors and officers as a group (8 persons) 20,885 *


* Less than 1%.

(a) Represents the number of common units Mr. Banks has the right to receive upon vesting of previous grants of phantom units within the next 60 days.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Our Relationship with Atlas Pipeline Partners, L.P.

Our cash generating assets consist of our interests in Atlas Pipeline Partners, L.P., a publicly traded Delaware limited partnership. Atlas is a midstream energyservice provider engaged in the transmission, gathering and processing of natural gas in the Mid−Continent and Appalachian regions. Our interests in Atlas willinitially consist of a 100% ownership interest in the general partner of Atlas, Atlas Pipeline GP, which owns:


• all of the incentive distribution rights in Atlas, which entitle us to receive increasing percentages, up to a maximum of 48.0%, of any cash distributed byAtlas as it reaches certain target distribution levels in excess of $0.42 per Atlas unit in any quarter; and

• 1,641,026 common units of Atlas, representing an approximate 12.8% limited partner interest in Atlas.Atlas is required by its partnership agreement to distribute all of its cash on hand at the end of each quarter, less reserves established by its general partner, in itssole discretion to provide for the proper conduct of Atlas’ business or to provide for future distributions. Our general partner will be reimbursed for direct andindirect expenses incurred on our behalf. Some of the non−independent directors of our general partner also serve as directors of Atlas’ general partner.

The Contribution AgreementPrior to the closing of this offering, the partnership interests we will own in Atlas, including the 2.0% general partner interest, the incentive distribution rights and1,641,026 common units, are held, directly or indirectly, by Atlas America. In connection with this offering, Atlas America and its affiliates have entered into aContribution Agreement pursuant to which, at closing, the 2% general partner interest, incentive distribution rights and 1,641,026 common units, eachrepresenting partnership interests in Atlas, will be contributed to us. As consideration for this contribution and in accordance with the terms of the ContributionAgreement, we will distribute substantially all of the proceeds we receive from this offering as well as 17,500,000 of our common units, assuming no exercise ofthe underwriters’ option to purchase additional units.

Registration RightsUnder our limited partnership agreement, we have agreed to register for sale under the Securities Act and applicable state securities laws (subject to certainlimitations) any common units proposed to be sold by owners of Atlas’ general partner or any of its respective affiliates. These registration rights require us tofile one registration statement. We have also agreed to include any securities held by the owners of Atlas’ general partner or any of its respective affiliates in anyregistration statement that we file to offer securities for cash, except that an offering relating solely to an employee benefit plan and other similar exceptions. Weare obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. These registration rights are in addition to theregistration rights that we have agreed to provide our general partner and its affiliates pursuant to our limited partnership agreement. Please read “Units Eligiblefor Future Sale.”

Indemnification of Directors and OfficersUnder our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and againstall losses, claims, damages or similar events any director or officer, or while serving as a director or officer, any person who is or was serving as a tax mattersmember or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our company or any of our affiliates. Additionally, wewill indemnify to the fullest extent permitted by law, from

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and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership at the time ofthe occurrence giving rise to the indemnity being sought.

Related Party Transactions Involving Atlas

On June 30, 2005, Resource America, Inc. (RAI) distributed its 10.7 million shares of Atlas America to its shareholders. In connection with this distribution ofAtlas America common stock to its shareholders, RAI and Atlas America entered into various agreements, including a shared services agreement and a taxmatters agreement, which govern the ongoing relationship between the two companies. Atlas is dependent upon the resources and services provided by AtlasAmerica, and through these agreements, RAI and its affiliates.

Under an agreement between Atlas and Atlas America, Atlas America must construct up to 2,500 feet of sales lines from its existing wells in the Appalachianregion to a point of connection to Atlas’ gathering systems. Atlas must, at its own cost, extend its system to connect to any such lines within 1,000 feet of itsgathering systems. With respect to wells to be drilled by Atlas America that will be more than 3,500 feet from Atlas’ gathering systems, Atlas has various optionsto connect those wells to its gathering systems at its own cost.

At December 31, 2005, Atlas’ general partner owned 1,641,026 common units constituting 12.8% of the limited partner interest in Atlas.

Atlas’ omnibus agreement and the natural gas gathering agreements with Atlas America and its affiliates were not the result of arms−length negotiations and,accordingly, Atlas cannot assure us that it could have obtained more favorable terms from independent third parties similarly situated. However, since theseagreements principally involve the imposition of obligations on Atlas America and its affiliates, Atlas does not believe that it could obtain similar agreementsfrom independent third parties.

In connection with the acquisition of Spectrum, Atlas entered into commitment agreements with Resource America and Atlas America for the purchase by themof up to $25.0 million of preferred units in Atlas Pipeline Operating Partnership, L.P., Atlas’ subsidiary. In consideration for their commitments, upon the closingof the Spectrum acquisition and the purchase by each of $10.0 million preferred units, Atlas paid Resource America and Atlas America commitment fees of$750,000 and $500,000, respectively.

In connection with the proposed acquisition of Alaska Pipeline Company, L.L.C., Atlas paid Resource America a fee of $70,750 in the year ended December 31,2004 for its commitment to repay certain financing that would have been required to complete the acquisition.

Atlas does not currently directly employ any persons to manage or operate its business. These functions are provided by employees of Atlas America and/or itsaffiliates. Atlas’ general partner does not receive a management fee in connection with its management of Atlas apart from its interest as general partner and itsright to receive incentive distributions.

Atlas reimburses its general partner, Atlas America and its affiliates for expenses they incur in managing its operations and for an allocation of the compensationpaid to the executive officers of its general partner, based upon an estimate of the time spent by such persons on activities for Atlas. Other indirect costs, such asrent for offices, are allocated to Atlas by Atlas America based on the number of its employees who devote substantially all of their time to activities on Atlas’behalf. Atlas reimburses Atlas America at cost for direct costs incurred by them on Atlas’ behalf. Atlas’ partnership agreement provides that its general partnerswill determine the costs and expenses that are allocable to Atlas in any reasonable manner determined by its general partner at its sole discretion.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

General. Conflicts of interest exist and may arise in the future as a result of the relationships among us, Atlas and our and its respective general partners andaffiliates. The directors and officers of Atlas’ general partner have fiduciary duties to manage Atlas in a manner beneficial to us, its owner. At the same time,Atlas’ general partner has a fiduciary duty to manage Atlas in a manner beneficial to Atlas and its limited partners. The managing board or the conflictscommittee of the managing board of Atlas will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. Theresolution of these conflicts may not always be in our best interest or that of our unitholders.

Conflicts Between Our General Partner and Its Affiliates and Our Partners. Whenever a conflict arises between our general partner or its affiliates, on the onehand, and us or any of our other partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions thatmodify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders foractions taken that, without those limitations, might constitute breaches of our general partner’s fiduciary duty to us.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

• approved by the audit and conflicts committee, although our general partner is not obligated to seek such approval;

• approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may beparticularly favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the audit and conflicts committee of its board. If our general partnerdoes not seek approval from the audit and conflicts committee and its board of directors determines that the resolution or course of action taken with respect tothe conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, theboard of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting suchproceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement,our general partner or the audit and conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When ourpartnership agreement requires someone to act in good faith, it requires that person to believe that he is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

Actions taken by our general partner may affect the amount of cash available for distribution to our common unitholders.The amount of cash that is available for distribution to our common unitholders is affected by decisions of our general partner regarding such matters as:

• amount and time of cash expenditures;

• asset sales or acquisitions;

• borrowings;

• the issuance of additional units;

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• the creation, reduction or increase of reserves in any quarter; and

• corporate opportunities.

We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff andsupport services to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable mannerdetermined by our general partner in its sole discretion. Please read “Certain Relationships and Related Party Transactions.”

Our general partner intends to limit its liability regarding our obligations.Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our generalpartner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of ourgeneral partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us,the right to enforce the obligations of our general partner and its affiliates in our favor.

If we are presented with certain business opportunities, Atlas will have the first right to pursue such opportunities.

Pursuant to the omnibus agreement to be entered into in connection with the closing of this offering, we will agree to certain business opportunity arrangementsto address potential conflicts that may arise between us and Atlas. If a business opportunity in respect of any business activity in which Atlas is currently engagedis presented to us, our general partner or Atlas or its general partner, then Atlas will have the first right to pursue such business opportunity. The omnibusagreement will provide, among other things, that Atlas will be presumed to desire to acquire the assets until such time as it advises us that it has abandoned suchpursuit, and we may not pursue the opportunity prior to that time.

Atlas and affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our abilityto acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to ourunitholders.

Neither our partnership agreement nor the omnibus agreement between us, Atlas, Atlas Pipeline GP and Atlas Pipeline Holdings GP, LLC will prohibit Atlas oraffiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us or one another. In addition, Atlas and itsaffiliates or affiliates of our general partner, may acquire, construct or dispose of additional assets related to the transmission, gathering and processing of naturalgas, NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. As a result, competitionamong these entities could adversely impact Atlas’ or our results of operations and cash available for distribution.

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Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s−length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Ourgeneral partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of theother agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are or will be the result ofarm’s−length negotiations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Common units are subject to our general partner’s limited call right.Our general partner may exercise its right to call and purchase common units as provided in our partnership agreement or assign this right to one of its affiliatesor to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a commonunitholder may have his common units purchased from him at an undesirable time or price.

We may not choose to retain separate counsel for ourselves or for the holders of common units.The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner.Attorneys, independent accountants and others who will perform services for us are selected by our general partner or the conflicts committee, if established, andmay perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of our common units in the event of aconflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of our common units, on the other, depending on thenature of the conflict. We do not intend to do so in most cases.

Acquisitions of Competing Businesses; Potential Future Conflicts. From time to time, we or our affiliates may acquire entities whose businesses compete withus or Atlas. In addition, future conflicts of interest may arise among us and any entities whose general partner interests we or our affiliates acquire or betweenAtlas and such entities. It is not possible to predict the nature or extent of these potential future conflicts of interest at this time, nor is it possible to determinehow we will address and resolve any such future conflicts of interest. However, the resolution of these conflicts may not always be in our best interest or those ofour unitholders. We do not currently intend to take any action which would limit the ability of Atlas to pursue its business strategy.

Fiduciary DutiesOur general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law andour partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides thatDelaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limitedpartners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. Wehave adopted these restrictions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflictsof interest. These modifications are detrimental to the common unitholders because they restrict the remedies available to unitholders for actions that, withoutthose limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary dutiesowed by our general partner to the unitholders:

State−law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with duecare and loyalty. The duty of care, in the absence of a provision in a

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partnership agreement providing otherwise, would generally require a general partner to act forthe partnership in the same manner as a prudent person would act on his own behalf. The duty ofloyalty, in the absence of a provision in a partnership agreement providing otherwise, wouldgenerally prohibit a general partner of a Delaware limited partnership from taking any action orengaging in any transaction where a conflict of interest is present.

The Delaware Act generally provides that a limited partner may institute legal action on behalf ofthe partnership to recover damages from a third party where a general partner has refused toinstitute the action or where an effort to cause a general partner to do so is not likely to succeed. Inaddition, the statutory or case law of some jurisdictions may permit a limited partner to institutelegal action on behalf of himself and all other similarly situated limited partners to recoverdamages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our generalpartner and its affiliates that might otherwise raise issues about compliance with fiduciary dutiesor applicable law. For example, our partnership agreement provides that when our general partneris acting in its capacity as our general partner, as opposed to in its individual capacity, it must actin “good faith” and will not be subject to any other standard under applicable law. In addition,when our general partner is acting in its individual capacity, as opposed to in its capacity as ourgeneral partner, it may act without any fiduciary obligation to us or the unitholders whatsoever.These standards reduce the obligations to which our general partner would otherwise be held.

In addition to the other more specific provisions limiting the obligations of our general partner,our partnership agreement further provides that our general partner and its officers and directorswill not be liable for monetary damages to us, our unitholders or assignees for errors of judgmentor for any acts or omissions unless there has been a final and non−appealable judgment by a courtof competent jurisdiction determining that the general partner or its officers and directors acted inbad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted withthe knowledge that such conduct was unlawful.

Special provisions regarding affiliated transactions. Our partnership agreement generallyprovides that affiliated transactions and resolutions of conflicts of interest not involving a vote ofunitholders and that are not approved by the conflicts committee of the board of directors of ourgeneral partner must be:

• on terms no less favorable to us than those generally being provided to or available fromunrelated third parties; or

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• “fair and reasonable” to us, taking into account the totality of the relationships between theparties involved (including other transactions that may be particularly favorable oradvantageous to us).

If our general partner does not seek approval from the conflicts committee and its board ofdirectors determines that the resolution or course of action taken with respect to the conflict ofinterest satisfies either of the standards set forth in the bullet points above, then it will bepresumed that, in making its decision, the board of directors, which may include board membersaffected by the conflict of interest, acted in good faith and in any proceeding brought by or onbehalf of any unitholders or the partnership, the person bringing or prosecuting such proceedingwill have the burden of overcoming such presumption. These standards reduce the obligations towhich our general partner would otherwise be held.

In order to become one of our limited partners, a unitholder is required to agree to be bound by the provisions in our partnership agreement, including theprovisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability ofpartnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceableagainst that person.

We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, againstliabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final andnon−appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. Wemust also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct wasunlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent these provisions purport toinclude indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore,unenforceable. Please read “Description of Our Partnership Agreement—Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights orprivileges available to unitholders under our partnership agreement. For a description of the rights and preferences of holders of common units in and topartnership distributions, please read this section and “Cash Distribution Policy.” For a description of the rights and privileges of unitholders under ourpartnership agreement, including voting rights, please read “The Partnership Agreement of Atlas Pipeline Holdings, L.P.”

Transfer Agent and Registrar

DutiesAmerican Stock Transfer and Trust Company will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agentfor transfers of common units except the following that must be paid by unitholders:

• surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

• special charges for services requested by a common unitholder; and

• other similar fees or charges.There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders,directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for anyliability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or RemovalThe transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointmentof a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common UnitsBy transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect tothe common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

• represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

• automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

• gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are enteringinto in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on ourbooks and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to thosethat it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

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Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, thetransferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes,except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT OF ATLAS PIPELINE HOLDINGS, L.P.

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included as Appendix A in thisprospectus.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

• with regard to distributions of available cash, please read “Cash Distribution Policy and Restrictions on Distributions;”

• with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties;”

• with regard to rights of holders of units, please read “Description of the Common Units;” and

• with regard to allocations of taxable income, taxable loss and other matters, please read “Material Tax Consequences.”Organization and Duration

We were formed on December 15, 2005 and have a perpetual existence.

Purpose

Under our partnership agreement, we are permitted to engage, directly or indirectly, in any business activity that is approved by our general partner and thatlawfully may be conducted by a limited partnership organized under Delaware law and, in connection therewith, to exercise all of the rights and powersconferred upon us pursuant to the agreements relating to such business activity; provided, however, that our general partner may not cause us to engage, directlyor indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwisetaxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us, our affiliates or our subsidiaries to engage in activities other than the ownership of partnership interestsin Atlas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limitedpartners, including any duty to act in good faith or in the best interest of us or our limited partners. Our general partner is authorized in general to perform all actsit determines to be necessary or appropriate to carry out our purposes and to conduct our business. For a further description of limits on our business, please read“Certain Relationships and Related Transactions.”

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if appointed, aliquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power ofattorney also grants the authority to amend, and to make consents and waivers under, our partnership agreement. Please read “—Amendments to Our PartnershipAgreement.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts inconformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount ofcapital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that theright, or exercise of the right, by the limited partners as a group:

• to remove or replace the general partner;

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• to approve some amendments to the partnership agreement; or

• to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could be held personally liable for ourobligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us andreasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourseagainst our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limitedpartner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other thanliabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership,would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, theDelaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limitedpartnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receivesa distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for theamount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of hisassignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partnerand that could not be ascertained from the partnership agreement.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. While we currentlyhave no operations distinct from Atlas, if in the future, by our ownership in an operating company or otherwise, it were determined that we were conductingbusiness in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right bythe limited partners as a group to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action underour partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limitedpartners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances.We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. In voting their units, affiliates of our general partner will have nofiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

Issuance of additional units No approval right.

Amendment of our partnership agreement Certain amendments may be made by our general partner without the approval of our unitholders.Other amendments generally require the approval of a majority of our outstanding units. Pleaseread “—Amendments to Our Partnership Agreement.”

Merger of our partnership or the sale of allor substantially all of our assets

A majority of our outstanding units in certain circumstances. Please read “—Merger, Sale orOther Disposition of Assets.”

Dissolution of our partnership A majority of our outstanding units. Please read “—Termination or Dissolution.”

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Continuation of our business upon dissolution A majority of our outstanding units. Please read “—Termination or Dissolution.”

Withdrawal of our general partner Under most circumstances, the approval of a majority of the units, excluding units held by ourgeneral partner and its affiliates, is required for the withdrawal of the general partner prior toDecember 30, 2015 in a manner that would cause a dissolution of our partnership. Please read“—Withdrawal or Removal of Our General Partner.”

Removal of our general partner Not less than 66 2/3 of the outstanding units, including units held by our general partner and itsaffiliates. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest Our general partner may transfer all, but not less than all,of its general partner interest in us without a vote of our unitholders to (i) an affiliate (other thanan individual) or (ii) another entity in connection with its merger or consolidation with or into, orsale of all or substantially all of its assets to, such person. The approval of a majority of the units,excluding units held by the general partner and its affiliates, is required in other circumstances fora transfer of the general partner interest to a third party prior to December 31, 2015. Please read“—Transfer of General Partner Interest.”

Transfer of ownership interests inour general partner No approval required at any time. Please read “—Transfer of Ownership Interests in Our General

Partner.”

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities on terms and conditionsestablished by our general partner in its sole discretion without the approval of our unitholders.

It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will beentitled to share equally with the then−existing holders of units in our cash distributions. In addition, the issuance of additional partnership interests may dilutethe value of the interests of the then−existing holders of units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion ofour general partner, may have special voting rights to which units are not entitled.

Amendments to Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no dutyor obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including anyduty to act in good faith or in the best interests of us or the limited partners. To adopt a proposed amendment, other than the amendments discussed below, ourgeneral partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the

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limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a majority of ouroutstanding units.

Prohibited Amendments

No amendment may be made that would:

(1) enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interestsso affected; or

(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwisepayable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) or (2) above can be amended upon theapproval of the holders of at least 90% of the outstanding units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

(1) a change in the name of the partnership, the location of the partnership’s principal place of business, the partnership’s registered agent or its registeredoffice;

(2) the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

(3) a change that, in the sole discretion of our general partner, is necessary or advisable for the partnership to qualify or to continue our qualification as alimited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the partnership will notbe treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

(4) an amendment that is necessary, in the opinion of our counsel, to prevent the partnership or our general partner or its directors, officers, agents ortrustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “planasset” regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulationscurrently applied or proposed;

(5) an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights toacquire partnership securities;

(6) any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

(7) an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

(8) any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by the partnership of, or its investment in, anycorporation, partnership or other entity, as otherwise permitted by our partnership agreement;

(9) a change in our fiscal year or taxable year and related changes;

(10) certain mergers or conveyances set forth in our partnership agreement; and

(11) any other amendments substantially similar to any of the matters described in (1) through (9) above.

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In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee if our generalpartner determines, at its option, that those amendments:

(1) do not adversely affect our limited partners in any material respect;

(2) are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of anyfederal or state agency or judicial authority or contained in any federal or state statute;

(3) are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of anysecurities exchange on which the limited partner interests are or will be listed for trading;

(4) are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnershipagreement; or

(5) are required to effect the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Finally, our partnership agreement specifically permits our general partner to authorize the general partner of Atlas to limit or modify the incentive distributionrights held by us if our general partner determines that such limitation or modification does not adversely affect our limited partners in any material respect.

Opinion of Counsel and Unitholder Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners orresult in none of us, Atlas or Atlas’s intermediate or operating partnerships being treated as an entity for federal income tax purposes in connection with any ofthe amendments described under “—No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval ofholders of at least 90% of the outstanding units unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liabilityunder applicable law of any of our limited partners. Any amendment that reduces the voting percentage required to take any action must be approved by theaffirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

Our partnership agreement generally prohibits our general partner, without the prior approval of a majority of our outstanding units, from causing us to, amongother things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by wayof merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of oursubsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without thatapproval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without thatapproval.

If conditions specified in our partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey some or all of ourassets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity.The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger orconsolidation, a sale of substantially all of our assets or any other transaction or event.

Termination or Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

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(1) the election of our general partner to dissolve us, if approved by the holders of a majority of our outstanding units, excluding those units held by ourgeneral partner and its affiliates;

(2) there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

(3) the entry of a decree of judicial dissolution of our partnership; or

(4) the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transferof its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under clause (4) above, the holders of a majority of our outstanding units excluding any units held by our general partner and its affiliates,may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointinga successor general partner an entity approved by the holders of a majority of our outstanding units, excluding those units held by our general partner and itsaffiliates, subject to receipt by us of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability of any limited partner; and

• none of our partnership nor the reconstituted limited partnership would be treated as an association taxable as a corporation or otherwise be taxable asan entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with allthe powers of our general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidationwill be applied as follows:

• first, towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and

• then, to all partners in accordance with the positive balance in the respective capital accounts.Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If theliquidator determines that a sale would be impractical or would cause a loss to our partners, our general partner may distribute assets in kind to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2015 without obtaining theapproval of a majority of our outstanding units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regardinglimited liability and tax matters. On or after December 31, 2015, our general partner may withdraw as general partner without first obtaining approval of anyunitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner maywithdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding common units are held or controlled by oneperson and its affiliates other than our general partner and its affiliates.

Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding units, excluding the units held by the withdrawing generalpartner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regardinglimited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of amajority of our outstanding units, excluding the units held by the withdrawing general partner and its affiliates, agree to continue our business and to appoint asuccessor general partner.

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Our general partner may not be removed unless that removal is approved by (i) the audit and conflicts committee of the general partner and (ii) not less than 662/3% of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability andtax matters. Any removal of our general partner is also subject to the approval of a successor general partner by a majority of our outstanding units, includingthose held by our general partner and its affiliates. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates wouldgive it the practical ability to prevent its removal. Upon completion of this offering, Atlas America will own approximately 82.9% of the outstanding units,assuming no exercise of its underwriters’ option to purchase additional units.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, allemployee−related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or itsaffiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:

• an affiliate of the general partner (other than an individual); or

• another entity as part of the merger or consolidation of the general partner with or into another entity or the transfer by the general partner of all orsubstantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner interest in us to another entity prior to December 31, 2015 without the approval of amajority of the common units outstanding, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transfereemust assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counselregarding limited liability and tax matters.

Transfer of Ownership Interests in Our General Partner

At any time, Atlas America, Inc., as the sole member of our general partner, may sell or transfer all or part of its ownership interest in the general partner withoutthe approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner asgeneral partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% ormore of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquiresthe units from our general partner or its affiliates and any transferees of that person or group approved by our general partner.

Limited Call Right

If at any time our general partner and its affiliates hold more than 87.5% of the outstanding limited partner interests of any class, our general partner will have theright, but not the obligation, which it may assign in whole or in part to any of its affiliates or us, to acquire all, but not less than all, of the remaining limitedpartner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least ten but not more than 60 days’notice. The purchase price in the event of this purchase is the greater of:

• the highest cash price paid by either our general partner or any of its affiliates for any limited partners interests of the class purchased within the 90days preceding the date our general partner first mails notice of its election to purchase the limited partner interests; and

• the current market price of the limited partner interests of the class as of the date three days prior to the date that notice is mailed.

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As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partnerinterests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholderof his units in the market. Please read “Material Tax Consequences—Disposition of Units.”

Upon completion of this offering, Atlas America will own 17,500,000 of our common units, representing approximately 82.9% of our outstanding common units,assuming no exercise of the underwriters’ option to purchase additional units.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of units then outstanding, unitholders on the record date will be entitled to notice of,and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by non−citizen assignees willbe voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units arecast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to betaken by our unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signedby holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our generalpartner or by unitholders owning at least 20% of the outstanding units. Unitholders may vote either in person or by proxy at meetings. The holders of a majorityof the outstanding units, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greaterpercentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights couldbe issued. Please read “—Issuance of Additional Securities” above. However, if at any time any person or group, other than our general partner and its affiliates,or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of anyclass of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not beconsidered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for othersimilar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of thebeneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our partnership agreement willbe delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect tothe transferred units when such transfer and admission is reflected in our books and records. Except as described under “—Limited Liability,” the common unitswill be fully paid, and unitholders will not be required to make additional contributions.

Non−Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk ofcancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we mayredeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require eachlimited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality,citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that thelimited partner is not an eligible citizen, the

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limited partner may be treated as a non−citizen assignee. A non−citizen assignee is entitled to an interest equivalent to that of a limited partner for the right toshare in allocations and distributions from us, including liquidating distributions. A non−citizen assignee does not have the right to direct the voting of his unitsand may not receive distributions in kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against alllosses, claims, damages or similar events:

(1) our general partner;

(2) any departing general partner;

(3) any person who is or was an affiliate of our general partner or any departing general partner;

(4) any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above;

(5) any person who is or was serving as an officer, director, member, partner, fiduciary or trustee of another person at the request of the general partner orany departing general partner; and

(6) any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or haveany obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities assertedagainst and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under thepartnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and allother expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus,incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by itsaffiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financialreporting purposes on an accrual basis. For tax reporting purposes, our fiscal year end is September 30. For fiscal reporting purposes, our fiscal year is thecalendar year.

We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financialstatements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make availablesummary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year.This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability tofurnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder willreceive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether hesupplies us with information.

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Right to Inspect Our Books and Records

A limited partner can, for a purpose reasonably related to the limited partner’s interest as a limited partner, upon reasonable demand stating the purpose of suchdemand and at his own expense, obtain:

• a current list of the name and last known address of each partner;

• a copy of our tax returns;

• information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to becontributed by each partner and the date on which each became a partner;

• copies of our partnership agreement, our certificate of limited partnership, amendments to either of them and powers of attorney which have beenexecuted under our partnership agreement;

• information regarding the status of our business and financial condition; and

• any other information regarding our affairs as is just and reasonable.Our general partner may, and intends to, keep confidential from the limited partners trade secrets and other information the disclosure of which our generalpartner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any units or other partnershipsecurities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwiseavailable. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible forFuture Sale.”

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THE PARTNERSHIP AGREEMENT OF ATLAS PIPELINE PARTNERS, L.P.

The following is a summary of the material provisions of Atlas’ partnership agreement.

Organization and Duration

Atlas was formed in May 1999. Atlas will dissolve on December 31, 2098, unless sooner dissolved under the terms of Atlas’ partnership agreement.

Purpose

Atlas’ purpose under its partnership agreement is limited to serving as the limited partner of its operating partnership and engaging in any business activity thatmay be engaged in by its operating partnership or that is approved by Atlas’ general partner. The operating partnership agreement provides that Atlas’ operatingpartnership may, directly or indirectly, engage in:

• operations as conducted on February 2, 2000, including the ownership and operation of Atlas’ gathering systems;

• any other activity approved by Atlas’ general partner, but only to the extent that the general partner reasonably determines that, as of the date of theacquisition or commencement of the activity, the activity generates “qualifying income” as that term is defined in Section 7704 of the Internal RevenueCode; or

• any activity that enhances the operations described above.The Units

Atlas’ common units represent limited partner interests in Atlas. The holders of units are entitled to participate in partnership distributions and exercise the rightsor privileges available to limited partners under Atlas’ partnership agreement.

Limited Voting Rights

Holders of Atlas’ units have limited voting rights and generally are entitled to vote only with respect to the following matters:

• a sale or exchange of all or substantially all of our assets;

• our dissolution or reconstitution;

• our merger; and

• termination or material modification of the omnibus agreement or master natural gas gathering agreement.Removal of Atlas’ general partner requires a two−thirds vote of all outstanding common units, excluding those held by Atlas’ general partner and its affiliates.Atlas’ partnership agreement permits us generally to make amendments to it that do not materially adversely affect unitholders without the approval of anyunitholders.

Cash Distribution Policy

Quarterly Distributions of Available Cash

Atlas’ operating partnership is required by the operating partnership agreement to distribute to Atlas, within 45 days of the end of each fiscal quarter, all of itsavailable cash for that quarter. Atlas, in turn, distributes to its partners all of the available cash received from its operating partnership for that quarter.

Available cash generally means, for any of Atlas’ fiscal quarters, all cash on hand at the end of the quarter less cash reserves that the general partner of Atlasdetermines are appropriate to provide for Atlas’ operating costs, including potential acquisitions, and to provide funds for distributions to the partners for any

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one or more of the next four quarters. Atlas generally makes distributions of all available cash within 45 days after the end of each quarter to holders of record onthe applicable record date.

Distributions of Available Cash from Operating Surplus

Cash distributions are characterized as distributions from either operating surplus or capital surplus. This distinction affects the amounts distributed to unitholdersrelative to Atlas’ general partner.

Operating surplus means:

• Atlas’ cash balance, excluding cash constituting capital surplus, less

• all of Atlas’ operating expenses, debt service payments, maintenance costs, capital expenditures and reserves established for future operations.Capital surplus means capital generated only by borrowings other than working capital borrowings, sales of debt and equity securities and sales or otherdispositions of assets for cash, other than inventory, accounts receivable and other assets disposed of in the ordinary course of business.

Atlas treats all available cash distributed from any source as distributed from operating surplus until the sum of all available cash distributed since Atlas beganoperations equals Atlas’ total operating surplus from the date Atlas began operations until the end of the quarter that immediately preceded the distribution. Thismethod of cash distribution avoids the difficulty of trying to determine whether available cash is distributed from operating surplus or capital surplus. Atlas treatsany excess available cash, irrespective of its source, as capital surplus, which would represent a return of capital, and Atlas’ general partner will distribute itaccordingly. For a discussion of distributions from capital surplus, see “—Distributions from Capital Surplus” below.

Atlas distributes available cash from operating surplus for any quarter in the following manner:

• first, 98% to all unitholders of Atlas, pro rata, and 2.0% to our subsidiary, Atlas Pipeline GP, as the general partner of Atlas, until Atlas has distributed$0.42 for each outstanding common unit; and

• after that, in the manner described in “—Incentive Distribution Rights” below.The 2.0% allocation of available cash from operating surplus to our subsidiary, as the general partner of Atlas, includes Atlas’ general partner’s percentageinterest in distributions from Atlas and Atlas’ operating partnership on a combined basis.

Adjusted operating surplus for any period generally means operating surplus generated during that period, less:

• any net increase in working capital borrowings during that period and

• any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period,and plus:

• any net decrease in working capital borrowings during that period and

• any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interestor premium.

Operating surplus generated during a period is equal to the difference between:

• the operating surplus determined at the end of that period and

• the operating surplus determined at the beginning of that period.

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Incentive Distribution Rights

By “incentive distribution rights” we mean our right to receive an increasing percentage of quarterly distributions of available cash from operating surplus afterAtlas has made the minimum quarterly distributions and Atlas has met specified target distribution levels, as described below. We may transfer our incentivedistribution rights separately from our general partner interest without the consent of the unitholders.

Atlas makes incentive distributions to us for any quarter in which it has distributed available cash from operating surplus to the common unitholders in an amountequal to the minimum quarterly distribution. If this condition is satisfied, the remaining available cash will be distributed as follows:

• first, 85.0% to all units, pro rata, 2.0% to the general partner and 13.0% to us, until a hypothetical unitholder has received a total of $0.52 per unit forthat quarter, in addition to any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterlydistribution on the common units;

• second, 75.0% to all units, pro rata, 2.0% to the general partner and 23.0% to us until a hypothetical unitholder has received a total of $0.60 per unit forthat quarter, in addition to any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterlydistribution on the common units; and

• after that, 50.0% to all units, pro rata, 2.0% to the general partner and 48% to us.The distributions to us that exceed its aggregate 2.0% general partner interest represent the incentive distribution rights.

Distributions from Capital Surplus

Atlas distributes available cash from capital surplus in the following manner:

• first, 98.0% to all units, pro rata, and 2.0% to the general partner, until each common unit issued in the initial public offering has received distributionsequal to $13.00 per unit; and

• after that, Atlas will distribute all available cash from capital surplus, as if it were from operating surplus.When Atlas makes a distribution from capital surplus, Atlas will treat it as if it were a repayment of a limited partner’s investment in its common units. For thesepurposes, the partnership agreement deems the investment to be $13.00 per common unit, which is the unit price from Atlas’ initial public offering. To reflectthis repayment, Atlas will reduce the amount of the minimum quarterly distribution and the distribution levels at which our incentive distribution rights begin,which we refer to in this prospectus as “target distribution levels,” by multiplying each amount by a fraction, determined as follows:

• the numerator is $13.00 less all distributions from capital surplus including the distribution just made, and

• the denominator is $13.00 less all distributions from capital surplus excluding the distribution just made.The initial public offering price of $13.00 per common unit, less any distributions from capital surplus, is referred to as the “unrecovered unit price.”

After the minimum quarterly distribution and the target distribution levels have been reduced to zero, Atlas will treat all distributions of available cash from allsources as if they were from operating surplus. Because the minimum quarterly distribution and the target distribution levels will have been reduced to zero, wewill then be entitled to receive 48.0% of all distributions of available cash, in addition to any distributions to which we may be entitled as a holder of units.

Distributions from capital surplus will not reduce the minimum quarterly distribution or target distribution levels for the quarter in which they are distributed.

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Adjustment of Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjustments made upon a distribution of available cash from capital surplus, Atlas will proportionately adjust each of the following upward ordownward, as appropriate, if any combination or subdivision of units occurs:

• the minimum quarterly distribution, the target distribution levels, or the unrecovered unit price,

• the number of common units issuable upon conversion of the subordinated units, and

• other amounts calculated on a per unit basis.For example, if a two−for−one split of the common units occurs, Atlas will reduce the minimum quarterly distribution, the target distribution levels and theunrecovered initial unit price of the common units to 50% of their initial levels.

Atlas will not make any adjustment for the issuance of additional common units for cash or property.

Atlas may also adjust the minimum quarterly distribution and the target distribution levels if legislation is enacted or if existing law is modified or interpreted in amanner that causes Atlas or its operating partnership to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or localincome tax purposes. In this event, Atlas will reduce the minimum quarterly distribution and the target distribution levels for each quarter after that time toamounts equal to the product of:

• the minimum quarterly distribution and each of the target distribution levels multiplied by,

• one minus the sum of:

• the highest marginal federal income tax rate which could apply to the partnership that is taxed as a corporation plus:

• any increase in the effective overall state and local income tax rate that would have been applicable in the preceding calendar year as a result of the newimposition of the entity level tax, after taking into account the benefit of any deduction allowable for federal income tax purposes for the payment ofstate and local income taxes, but only to the extent of the increase in rates resulting from that legislation or interpretation.

For example, assuming Atlas is not previously subject to state and local income tax, if Atlas became taxable as a corporation for federal income tax purposes andsubject to a maximum marginal federal, and effective state and local, income tax rate of 40%, then Atlas would reduce the minimum quarterly distribution andthe target distribution levels to 60% of the amount immediately before the adjustment.

Distributions of Cash Upon Liquidation

When Atlas commences dissolution and liquidation, Atlas will sell or otherwise dispose of its assets and adjust the partners’ capital account balances to reflectany resulting gain or loss. Atlas will first apply the proceeds of liquidation to the payment of our creditors in the order of priority provided in Atlas’ partnershipagreement and by law. After that, Atlas will distribute the proceeds to the unitholders and our general partner in accordance with their capital account balances,as so adjusted.

Atlas maintains capital accounts in order to ensure that the partnership’s allocations of income, gain, loss and deduction are respected under the Internal RevenueCode. The balance of a partner’s capital account also determines how much cash or other property the partner will receive on liquidation of the partnership. Apartner’s capital account is credited with (increased by) the following items:

• the amount of cash and fair market value of any property (net of liabilities) contributed by the partner to the partnership; and

• the partner’s share of “book” income and gain (including income and gain exempt from tax).A partner’s capital account is debited with (reduced by) the following items:

• the amount of cash and fair market value (net of liabilities) of property distributed to the partner; and

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• the partner’s share of loss and deduction (including some items not deductible for tax purposes).

Partners are entitled to liquidating distributions in accordance with their capital account balances.

Upon our liquidation, any gain, or unrealized gain attributable to assets distributed in kind, will be allocated to the partners in the following manner:

• first, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to thosenegative balances;

• second, 98% to the common units, pro rata, and 2.0% to the general partner, until the capital account for each common unit is equal to the sum of:

the unrecovered unit price, and the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

• third, 85% to all units, pro rata, 2.0% to the general partner and 13.0% to us, until there has been allocated under this paragraph an amount per unitequal to:

the excess of the $0.52 target distribution per unit over the minimum quarterly distribution per unit for each quarter of Atlas’ existence less:

the cumulative amount per unit of any distribution of available cash from operating surplus in excess of the minimum quarterly distribution perunit that was distributed 85.0% to the units, pro rata, and 15% to us for each quarter of our existence;

• fourth, 75.0% to all units, pro rata, 2.0% to the general partner and 23.0% to us, until there has been allocated under this paragraph an amount per unitequal to:

the excess of the $0.60 target distribution per unit over the $0.52 target distribution per unit for each quarter of our existence less:

the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit thatwas distributed 75.0% to the units, pro rata, and 23.0% to us for each quarter of our existence; and

• after that, 50.0% to all units, pro rata, 48.0% to us and 2.0% to our general partner.Upon Atlas’ liquidation, any loss will generally be allocated to us and the unitholders in the following manner:

• first, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to us, until the capital accounts ofthe common unitholders have been reduced to zero; and

• after that, 100.0% to us.In addition, Atlas will make interim adjustments to the capital accounts at the time Atlas issues additional equity interests or makes distributions of property.Atlas will base these adjustments on the fair market value of the interests or the property distributed and Atlas will allocate any gain or loss resulting from theadjustments to the unitholders and us in the same manner as Atlas allocates gain or loss upon liquidation. In the event that Atlas makes positive interimadjustments to the capital accounts, Atlas will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional equityinterests, Atlas’ distributions of property, or upon Atlas’ liquidation, in a manner which results, to the extent possible, in the capital account balances of usequaling the amount which would have been our general partner’s capital account balances if we had not made any earlier positive adjustments to the capitalaccounts.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder and executes and delivers a transfer application, grants to the general partner and, ifappointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution and

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the amendment of Atlas’ partnership agreement, and to make consents and waivers under Atlas’ partnership agreement.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Limited Liability

So long as a limited partner does not participate in the control of Atlas’ business within the meaning of the Delaware Revised Uniform Limited Partnership Actand otherwise acts in conformity with the provisions of Atlas’ partnership agreement, the limited partner’s liability under the Delaware Act will be limited to theamount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined that alimited partner participated in the control of Atlas’ business, then the limited partner could be held personally liable for Atlas’ obligations under Delaware law tothe same extent as the general partner. This liability would extend only to persons who transact business with Atlas who reasonably believe that the limitedpartner is a general partner. However, what constitutes participating in the control of a limited partnership’s business has not been clearly established in all states.If it were determined, for example, that the right, or exercise of a right, by the limited partners to:

• remove Atlas’ general partner;

• approve some amendments to our partnership agreement; or

• take other action under our partnership agreement;constituted participation in the control of our business, then limited partners could be held liable for our obligations to the same extent as the general partner.

Under the Delaware Act, Atlas cannot make a distribution to a partner if, after the distribution, all its liabilities, other than liabilities to partners on account oftheir partnership interests and liabilities for which the recourse of creditors is limited to specific property, exceed the fair value of Atlas’ assets. For the purposeof determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourseof creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourseliability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was inviolation of the Delaware Act is liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee whobecomes a substituted limited partner is liable for the obligations of his assignor to make contributions to the partnership, except the assignee is not obligated forliabilities unknown to him at the time he became a limited partner and which he could not ascertain from Atlas’ partnership agreement.

Atlas’ operating partnership currently conducts business in Arkansas, Missouri, New York, Ohio, Oklahoma, Pennsylvania and Texas. The limitations on theliability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If it were determined that Atlaswas, by virtue of its limited partner interest in its operating partnership or otherwise, conducting business in any state under the applicable limited partnershipstatute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to ourpartnership agreement, or to take other action under Atlas’ partnership agreement constituted “participation in the control” of Atlas’ business for purposes of thestatutes of any relevant jurisdiction, then the limited partners could be held personally liable for Atlas’ obligations under the law of that jurisdiction to the sameextent as the general partner. Atlas operates in a manner we consider reasonable and appropriate to preserve the limited liability of the limited partners.

Transfer Agent and Registrar

American Stock Transfer and Trust Company is our registrar and transfer agent for the common units. Atlas pays all fees charged by the transfer agent fortransfers of common units, except that the following fees must be paid by unitholders:

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• surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

• special charges for services requested by a holder of a common unit; and

• other similar fees or charges.

There is no charge to unitholders for disbursements of cash distributions.

Atlas will indemnify the transfer agent, its agents and each of their particular shareholders, directors, officers and employees against all claims and losses thatmay arise out of acts performed or omitted in its capacity as Atlas’ transfer agent, except for any liability due to any negligence, gross negligence, bad faith orintentional misconduct of the indemnified person or entity.

Transfer of Common Units

The transfer agent will not record a transfer of common units, and Atlas will not recognize the transfer, unless the transferee executes and delivers a transferapplication. The form of transfer application appears on the reverse side of the certificates representing the common units. By executing and delivering a transferapplication, the transferee of common units:

• becomes the record holder of the common units and is an assignee until admitted as a substituted limited partner;

• automatically requests admission as a substituted limited partner;

• agrees to be bound by the terms and conditions of our partnership agreement;

• represents that the transferee has the capacity, power and authority to enter into Atlas’ partnership agreement;

• grants powers of attorney to officers of our general partner and our liquidator, as specified in Atlas’ partnership agreement; and

• makes the consents and waivers contained in Atlas’ partnership agreement.An assignee will become a substituted limited partner as to the transferred common units upon the consent of the general partner and the recordation of the nameof the assignee on the general partner’s books and records. The general partner may withhold its consent in its sole discretion.

A transferee’s broker, agent or nominee may complete, execute and deliver the transfer applications. Atlas is entitled to treat the nominee holder of a commonunit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreementbetween the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to the rights acquired upon transfer, thetransferor gives the transferee the right to request admission as a substituted limited partner. A purchaser or transferee of common units who does not execute anddeliver a transfer application will have only:

• the right to assign the common units to a purchaser or other transferee; and

• the right to transfer the right to seek admission as a substituted limited partner.Thus, a purchaser or transferee of common units who does not execute and deliver a transfer application will not receive:

• cash distributions or federal income tax allocations unless the common units are held in a nominee or “street name” account and the nominee or brokerhas executed and delivered a transfer application; and

• may not receive federal income tax information or reports furnished to record holders of common units.

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The transferor of common units must provide the transferee with all information necessary to transfer the common units. The transferor will not be required toinsure the execution of the transfer application by the transferee and will have no liability or responsibility if the transferee neglects or chooses not to execute andforward the transfer application to the transfer agent. See “—Status as Limited Partner or Assignee.”

Until a common unit has been transferred on Atlas’ books, Atlas and the transfer agent may treat the record holder of the unit as the absolute owner for allpurposes, except as otherwise required by law or stock exchange regulations, even if Atlas or the transfer agent has notice of an attempted transfer.

Issuance of Additional Securities

Atlas’ partnership agreement authorizes it to issue an unlimited number of additional limited partner interests, debt and other securities for the consideration andon the terms and conditions established by the general partner in its sole discretion without the approval of any limited partners. Atlas has funded, and will likelycontinue to fund, acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units Atlas issueswill be entitled to share equally with the then−existing holders of common units in Atlas’ distributions of available cash. In addition, the issuance of additionalpartnership interests may dilute the value of the interests of the then−existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of Atlas’ partnership agreement, Atlas may also issue additional partnership securities that, in the solediscretion of the general partner, may have special voting rights to which the common units are not entitled.

Upon issuance of additional partnership securities, the general partner must make additional capital contributions to the extent necessary to maintain its combined2.0% general partner interest in Atlas and in Atlas’ operating partnership. We will be required to make corresponding capital contributions to the general partner.Moreover, the general partner will have the right, which it may from time to time assign in whole or in part to us or to any of our affiliates, to purchase commonunits, subordinated units or other equity securities, whenever, and on the same terms that, Atlas issues those securities to persons other than the general partnerand its affiliates, to the extent necessary to maintain its percentage interest that existed immediately before each issuance. The holders of common units will nothave preemptive rights to acquire additional common units or other partnership interests.

Amendment of Atlas’ Partnership Agreement

Amendments to Atlas’ partnership agreement may be proposed only by or with the consent of the general partner, which the general partner may withhold in itssole discretion. In order to adopt a proposed amendment, other than the amendments discussed in “—No Unitholder Approval” below, the general partner mustseek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote uponthe proposed amendment.

Prohibited Amendments

No amendment may be made that would:

• change the percentage of outstanding units required to take partnership action, unless approved by the affirmative vote of unitholders constituting atleast the voting requirement sought to be reduced;

• enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interestsso affected;

• enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwisepayable to the general partner or any of its affiliates without its consent, which may be given or withheld in its sole discretion;

• change Atlas’ term;

• provide that Atlas is not dissolved upon the expiration of its term or upon an election to dissolve it by us as the general partner that is approved byholders of a majority of the units of each class; or

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• give any person the right to dissolve Atlas other than the general partner’s right to dissolve Atlas with the approval of holders of a majority of the unitsof each class.

The provision of Atlas’ partnership agreement preventing the amendments having the effects described above can be amended upon the approval of the holdersof at least 90% of the outstanding units voting together as a single class.

No Unitholder Approval

The general partner may amend Atlas’ partnership agreement, without the approval of the unitholders, to:

• change Atlas’ name, the location of its principal place of business, its registered agent or registered office;

• reflect the admission, substitution, withdrawal or removal of partners in accordance with Atlas’ partnership agreement;

• qualify Atlas or continue its qualification as a limited partnership under the laws of any state or to ensure that neither Atlas nor its operating partnershipwill be taxed as a corporation or otherwise taxed as an entity for federal income tax purposes;

• prevent Atlas or the general partner, or its directors, officers, agents or trustees, from being subject to the provisions of the Investment Advisers Act of1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974;

• authorize additional limited or general partner interests;

• reflect changes required by a merger agreement that has been approved under the terms of Atlas’ partnership agreement;

• permit Atlas to form or invest in any entity, other than the operating partnership, permitted by its partnership agreement;

• change Atlas’ fiscal year or taxable year; and

• make other changes substantially similar to any of the matters described above.In addition, the general partner may amend Atlas’ partnership agreement, without the approval of the unitholders, if those amendments:

• do not adversely affect the limited partners in any material respect;

• are necessary to satisfy any requirements or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency orjudicial authority or contained in any federal or state statute;

• are necessary to facilitate the trading of limited partner interests or to comply with any rule or guideline of any securities exchange or interdealerquotation system on which the limited partner interests are or will be listed for trading;

• are necessary for any action taken by the general partner relating to splits or combinations of units; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of Atlas’ partnership agreement or are otherwisecontemplated by Atlas’ partnership agreement.

Opinion of Counsel and Unitholder Approval

Except in the case of the amendments described above under “—No Unitholder Approval,” amendments to Atlas’ partnership agreement will not becomeeffective without the approval of holders of at least 90% of the units unless Atlas obtains an opinion of counsel to the effect that the amendment will not affectthe limited liability under applicable law of any limited partner or cause Atlas or Atlas’ operating partnership to be taxable as a corporation or otherwise to betaxed as an entity for federal income tax purposes (to the extent not previously taxed as such). Subject to obtaining the opinion of counsel, any amendment thatwould have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation

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to other classes of units will require the approval of at least a majority of the type or class of units so affected.

Merger, Sale or Other Disposition of Assets of Atlas

The general partner may not, without the prior approval of holders of a majority of the outstanding units of each class, sell, exchange or otherwise dispose of allor substantially all of Atlas’ assets, including by way of merger, consolidation or other combination, or approve on behalf of Atlas the sale, exchange or otherdisposition of all or substantially all of the assets of Atlas’ operating partnership. However, the general partner may mortgage or otherwise grant a securityinterest in all or substantially all of its assets or sell all or substantially all of Atlas’ assets under a foreclosure without that approval. Furthermore, provided thatconditions specified in Atlas’ partnership agreement are satisfied, the general partner may merge Atlas or any of its subsidiaries into, or convey some or all ofAtlas’ and its subsidiaries assets to, a newly formed entity if the sole purpose of that merger or conveyance changes our legal form into another limited liabilityentity.

The unitholders are not entitled to dissenters’ rights of appraisal in the event of a merger, consolidation, sale of substantially all of our assets or any othertransaction or event.

Termination and Dissolution

Atlas will continue until December 31, 2098, unless terminated sooner upon:

• the election of the general partner to dissolve Atlas, if approved by the holders of a majority of the outstanding units of each class;

• the sale, exchange or other disposition of all or substantially all of Atlas’ assets and those of its operating partnership;

• the entry of a decree of judicial dissolution of Atlas; or

• the withdrawal or removal of the general partner or any other event that results in Atlas Pipeline GP ceasing to be Atlas’ general partner other than thetransfer of its general partner interest in accordance with Atlas’ partnership agreement or withdrawal or removal following approval and admission of asuccessor.

Upon a dissolution under the last item above, the holders of a majority of the units of each class may also elect, within specific time limitations, to reconstituteAtlas by forming a new limited partnership on terms identical to those in Atlas’ partnership agreement and having as general partner an entity approved by theholders of a majority of the units of each class subject to Atlas’ receipt of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability of any limited partner; and

• Atlas, the reconstituted limited partnership, and the operating partnership would not be taxed as a corporation or otherwise be taxed as an entity forfederal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Unless the general partner is reconstituted and continues as a new limited partnership, upon liquidation the liquidator will liquidate Atlas’ assets and apply theproceeds of the liquidation as described in “—Cash Distribution Policy—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation ordistribution of Atlas’ assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would causeundue loss to the partners.

Withdrawal or Removal of Atlas’ General Partner

Atlas’ general partner may withdraw as Atlas’ general partner without first obtaining approval from the unitholders by giving 90 days’ written notice. Atlas’general partner may also sell or otherwise transfer all of its general partner interests in Atlas without the approval of the unitholders as described below under“—Transfer of General Partner Interest and Incentive Distribution Rights.” Upon withdrawal, Atlas must

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reimburse the general partner for all expenses incurred by it on Atlas’ behalf or allocable to Atlas in connection with operating its business.

If the general partner withdraws, other than as a result of a transfer of all or a part of its general partner interests in Atlas, the holders of a majority of the unitsmay elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and taxmatters cannot be obtained, Atlas will be dissolved and liquidated, unless within 180 days after that withdrawal the holders of a majority of the units agree inwriting to continue Atlas’ business and to appoint a successor general partner.

The general partner may not be removed except by the vote of the holders of at least 66 2/3% of the outstanding common units, excluding common units held bythe general partner and its affiliates, and Atlas receives an opinion of counsel regarding limited liability and tax matters. Any removal is also subject to theapproval of a successor general partner by the vote of the holders of a majority of the common units, excluding common units held by us as the general partnerand our affiliates. If the general partner is removed under circumstances where cause does not exist and does not consent to that removal:

• the agreement of Atlas America to connect wells to Atlas’ gathering systems will terminate;

• the master natural gas gathering agreement with Atlas America will not apply to any future wells drilled by Atlas America although it will continue asto wells connected to the gathering system at the time of removal;

• the obligations of Atlas America to provide assistance for the extension of Atlas’ gathering systems and in the identification and acquisition ofgathering systems from third parties will terminate; and

• the general partner will have the right to convert its general partner interests and incentive distribution rights into common units or to receive cash inexchange for those interests from the successor general partner.

Atlas’ partnership agreement defines “cause” as existing where a court has rendered a final, non−appealable judgment that the general partner has committedfraud, gross negligence or willful or wanton misconduct in its capacity as general partner.

Withdrawal or removal of the general partner as Atlas’ general partner also constitutes withdrawal or removal as the general partner of Atlas’ operatingpartnership.

In the event of removal of the general partner under circumstances where cause exists or a withdrawal of the general partner that violates Atlas’ partnershipagreement, a successor general partner will have the option to purchase the general partner interests and incentive distribution rights of the departing generalpartner for a cash payment equal to the fair market value of those interests. Under all other circumstances where the general partner withdraws or is removed, thedeparting general partner will have the option to require the successor general partner to purchase those interests for their fair market value. In each case, fairmarket value will be determined by agreement between the departing general partner and the successor general partner. If they cannot reach an agreement, anindependent expert selected by the departing general partner and the successor general partner will determine the fair market value. If the departing generalpartner and the successor general partner cannot agree on an expert, then an expert chosen by agreement of the experts selected by each of them will determinethe fair market value. If the purchase option is not exercised by either the departing general partner or the successor general partner, the general partner interestsand incentive distribution rights will automatically convert into common units equal to the fair market value of those interests. The successor general partnermust indemnify the departing general partner (or its transferee) from all of Atlas’ debt and liability arising on or after the date on which the departing generalpartner becomes a common unitholder as a result of the conversion. Except for this limited indemnity right and the right of the departing general partner toreceive distributions on its common units, no other payments will be made to Atlas’ general partner after withdrawal.

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Transfer of General Partner Interest And Incentive Distribution Rights

Atlas’ general partner may transfer all or any part of its general partner interest without obtaining the consent of the unitholders. As a condition to the transfer ofa general partner interest, the transferee must assume the rights and duties of the general partner to whose interest it has succeeded, furnish an opinion of counselregarding limited liability and tax matters, agree to acquire all of the general partner’s interest in Atlas’ operating partnership and agree to be bound by theprovisions of the partnership agreement of our operating partnership.

The general partner’s members may sell or transfer all or part of their interest in the general partner to an affiliate without the approval of the unitholders. AtlasAmerica and its affiliates have agreed that they will not divest their interest in the general partner without also divesting to the same acquirer their ownershipinterest in subsidiaries which act as the general partner of oil and gas investment partnerships sponsored by them.

Atlas Pipeline GP or a later holder may transfer its incentive distribution rights to an affiliate or another person as part of its merger or consolidation with or into,or sale of all or substantially all of our assets to, that person without the prior approval of the unitholders. However, the transferee must agree to be bound by theprovisions of Atlas’ partnership agreement.

Change of Management Provisions

Atlas’ partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Atlas’ general partner orotherwise change management. If any person or group other than Atlas Pipeline GP and its affiliates acquires beneficial ownership of 20% or more of any classof units, that person or group will lose voting rights on all of its units and the units will not be considered outstanding for the purposes of noticing meetings,determining the presence of a quorum, calculating required votes and other similar matters. In addition, the removal of the general partner under circumstanceswhere cause does not exist and the general partner does not consent to that removal has the adverse consequences described under “—Withdrawal or Removal ofAtlas’ General Partner.”

Limited Call Right

If at any time not more than 20% of the outstanding limited partner interests of any class are held by persons other than the general partner and its affiliates, thegeneral partner will have the right, which it may assign in whole or in part to any of its affiliates or to Atlas, to acquire all, but not less than all, of the remaininglimited partner interests of the class held by unaffiliated persons as of a record date selected by the general partner on at least 10 but not more than 60 days’notice. The purchase price is the greater of:

• the highest cash price paid by the general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 dayspreceding the date on which the general partner first mails notice of its election to purchase those limited partner interests; and

• the current market price as of the date three days before the date the notice is mailed.As a result of the general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partnerinterests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholderof his common units in the market.

Meetings; Voting

Except as described above under “—Change of Management Provisions,” unitholders or assignees who are record holders of units on a record date will beentitled to notice of, and to vote at, meetings of Atlas’ limited partners and to act upon matters for which approvals may be solicited. Common units that areowned by an assignee who is a record holder, but who has not yet been admitted as a substituted limited partner, will be voted by the general partner at thewritten direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by thegeneral partner on behalf of non−citizen assignees, the general partner will distribute the votes on those common units in the same ratios as the votes of limitedpartners on other units are cast.

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Any action to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action sotaken are signed by holders of the same number of units as would be necessary to take the action. Meetings of the unitholders may be called by the generalpartner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or byproxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or byproxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorumwill be the greater percentage.

Except as described above under “—Change of Management Provisions,” each record holder will have a vote in accordance with his percentage interest,although additional limited partner interests having different voting rights could be issued. See “—Issuance of Additional Securities.” Common units held innominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner.

Atlas or the transfer agent will deliver any notice, report or proxy material required or permitted to be given or made to record holders of common units underAtlas’ partnership agreement to the record holder.

Status as Limited Partner or Assignee

The common units will be fully paid, and, except as described above under “—Limited Liability,” unitholders will not be required to make additionalcontributions.

An assignee of a common unit, after executing and delivering a transfer application, but pending its admission as a substituted limited partner, is entitled to aninterest equivalent to that of a limited partner sharing in allocations and distributions, including liquidating distributions. The general partner will vote andexercise other powers attributable to common units owned by an assignee who has not become a substituted limited partner at the written direction of theassignee. See “—Meetings; Voting.” Atlas will not treat transferees who do not execute and deliver a transfer application as assignees or as record holders ofcommon units, and they will not receive cash distributions, federal income tax allocations or reports furnished to record holders. See “—Transfer of CommonUnits.”

Non−Citizen Assignees; Redemption

If Atlas is or becomes subject to federal, state or local laws or regulations that, in the reasonable determination of us as the general partner, create a substantialrisk of cancellation or forfeiture of any property in which Atlas has an interest because of the nationality, citizenship or related status of any limited partner orassignee, Atlas may redeem the units held by the limited partner or assignee at their current market price. In order to avoid any cancellation or forfeiture, Atlasmay require each limited partner or assignee to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails tofurnish this information within 30 days after a request for it, or Atlas determines after receipt of the information that the limited partner or assignee is not aneligible citizen, then the limited partner or assignee may be treated as a non−citizen assignee. In addition to other limitations on the rights of an assignee who isnot a substituted limited partner, a non−citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind uponAtlas’ liquidation.

Indemnification

Under the partnership agreement, Atlas will indemnify the following persons, by reason of their status as such, to the fullest extent permitted by law, from andagainst all losses, claims or damages arising out of or incurred in connection with Atlas’ business:

• the general partner;

• any departing general partner;

• any person who is or was an affiliate of the general partner or any departing general partner;

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• any person who is or was a member, partner, officer, director, employee, agent or trustee of the general partner, any departing general partner or theoperating partnership or any affiliate of a general partner, any departing general partner or the operating partnership; or

• any person who is or was serving at the request of a general partner or any departing general partner or any affiliate of a general partner or anydeparting general partner as an officer, director, employee, member, partner, agent, fiduciary or trustee of another person.

Atlas’ indemnification obligation arises only if the indemnified person acted in good faith and in a manner the person reasonably believed to be in, and notopposed to, Atlas’ best interests. With respect to criminal proceedings, the indemnified person must not have had reasonable cause to believe that the conductwas unlawful.

Any indemnification under these provisions will be only out of Atlas’ assets. Atlas’ general partner will not be personally liable for the indemnificationobligations and will not have any obligation to contribute or loan funds to Atlas in connection with it. The partnership agreement permits Atlas to purchaseinsurance against liabilities asserted against and expenses incurred by persons for Atlas’ activities, regardless of whether Atlas would have the power toindemnify the person against liabilities under the partnership agreement.

Books and Reports

The general partner keeps appropriate books on Atlas’ business at Atlas’ principal offices. The books are maintained for both tax and financial reporting purposeson an accrual basis. For tax purposes, our fiscal year end is September 30. For financial reporting purposes, our fiscal year is the calendar year.

Atlas furnishes or makes available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing auditedfinancial statements and a report on those financial statements by Atlas’ independent public accountants. Except for its fourth quarter, Atlas also furnishes ormakes available summary financial information within 90 days after the close of each quarter.

Atlas furnishes each record holder information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. Atlas expectsto furnish information in summary form so that some complex calculations normally required of partners can be avoided. Atlas’ ability to furnish this summaryinformation to unitholders depends on the cooperation of unitholders in supplying it with specific information. Atlas will furnish every unitholder withinformation to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he suppliesAtlas with information.

Right to Inspect Our Books and Records

Atlas’ partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand andat his own expense, have furnished to him:

• a current list of the name and last known address of each partner;

• a copy of Atlas’ tax returns;

• information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to becontributed by each partner and the date on which each became a partner;

• copies of Atlas’ partnership agreement, the certificate of limited partnership and related amendments and powers of attorney under which they havebeen executed;

• information regarding the status of our business and financial condition; and

• other information regarding our affairs that is just and reasonable.The general partner may keep confidential from the limited partners trade secrets or other information the disclosure of which general partner believes in goodfaith is not in Atlas’ best interests or which Atlas is required by law or by agreements with third parties to keep confidential.

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Registration Rights

Under the partnership agreement, Atlas has agreed to register for resale under the Securities Act and applicable state securities laws any common units,subordinated units or other partnership securities proposed to be sold by the general partner or any of our affiliates if an exemption from the registrationrequirements is not otherwise available. Atlas is obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, management of our general partner will hold an aggregate of 17,500,000 common units, assuming no exerciseof the underwriters’ option to purchase additional units. The sale of these units could have an adverse impact on the price of the common units or on any tradingmarket that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that anycommon units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or underan exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does notexceed, during any three−month period, the greater of:

• 1% of the total number of the securities outstanding; or

• the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of currentpublic information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who hasbeneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public informationrequirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

The partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equitysecurities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributionsto and market price of, common units then outstanding. Please read “The Partnership Agreement of Atlas Pipeline Holdings, L.P.—Issuance of AdditionalSecurities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws theoffer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnershipagreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to requireregistration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by anyunitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. Inconnection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling personsfrom and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costsand expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and itsaffiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

Our partnership, our general partner and the directors and executive officers of our general partner, have agreed not to sell any common units they beneficiallyown for a period of 180 days from the date of this prospectus. For a description of these lock−up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of theUnited States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., tax counsel to the general partner and us, insofaras it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisionsof the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Laterchanges in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires,references in this section to “us” or “we” are references to Atlas Pipeline Holdings, L.P.

The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholderswho are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or otherunitholders subject to specialized tax treatment, such as tax−exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investmenttrusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state,local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson& Elkins L.L.P. and are based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson &Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, theopinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adverselyimpact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal,accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectlyby our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative oradministrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) thetreatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “Material Tax Consequences—TaxConsequences of Unit Ownership—Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted byexisting Treasury Regulations (please read “Material Tax Consequences —Disposition of Common Units—Allocations Between Transferors and Transferees”);and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “Material Tax Consequences—TaxConsequences of Unit Ownership—Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share ofitems of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made tohim by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’sadjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception,referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxableyear consists of “qualifying income.” Qualifying income includes income and gains derived from the

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transportation, storage, processing and marketing of crude oil, natural gas and products thereof, including our allocable share of such income from Atlas. Othertypes of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or otherdisposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our currentincome is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representationsmade by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current grossincome constitutes qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether ouroperations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Moreover, no ruling has been or will be sought from the IRS and theIRS has made no determination as to Atlas’ status for federal income tax purposes or whether its operations generate “qualifying income” under Section 7704 ofthe Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, publishedrevenue rulings and court decisions and the representations described below, we will be classified as a partnership for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us andour general partner upon which Vinson & Elkins L.L.P. has relied are:

(a) Neither we, nor Atlas will elect to be treated as a corporation; and

(b) For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifyingincome” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable timeafter discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year inwhich we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation oftheir interests in us. This contribution and liquidation should be tax−free to unitholders and us so long as we, at that time, do not have liabilities in excess of thetax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income,gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us atcorporate rates. Moreover, if Atlas were taxable as a corporation in any given year, our share of Atlas’ items of income, gain, loss and deduction would not bepassed through to us, and Atlas would pay tax on its income at corporate rates. In addition, any distribution made to a unitholder would be treated as eithertaxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return ofcapital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced tozero. Accordingly, taxation of either us or Atlas as a corporation would result in a material reduction in a unitholder’s cash flow and after−tax return and thuswould likely result in a substantial reduction of the value of the units.

The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we and Atlas will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Atlas Pipeline Holdings, L.P. will be treated as partners of Atlas Pipeline Holdings, L.P. for federal income taxpurposes. Also:

• assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners; and

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• unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantiverights attendant to the ownership of their common units will be treated as partners of Atlas Pipeline Holdings, L.P. for federal income tax purposes.

As there is no direct authority addressing assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct theexercise of attendant rights, but who fail to execute and deliver transfer applications, Vinson & Elkins L.L.P.’s opinion does not extend to those persons.Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income taxinformation or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executedand delivered a transfer application for those units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner withrespect to those units for federal income tax purposes. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Treatment of ShortSales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cashdistributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. Theseholders are urged to consult their own tax advisors with respect to their status as partners in Atlas Pipeline Holdings, L.P.

The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Atlas Pipeline Holdings, L.P. for federal income taxpurposes.

Tax Consequences of Unit Ownership

Flow−Through of Taxable Income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses anddeductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he hasnot received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for ourtaxable year ending with or within his taxable year. Our taxable year ends on September 30.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any suchcash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basisgenerally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition ofCommon Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss,known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amountto be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “Material Tax Consequences—TaxConsequences of Unit Ownership—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities,and thus will result in a corresponding deemed distribution of cash. A non−pro rata distribution of money or property may result in ordinary income to aunitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” includingdepreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.”To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in returnfor the non−pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinaryincome, which

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will equal the excess of (1) the non−pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemedrelinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date fordistributions for the period ending , will be allocated an amount of federal taxable income for that period that will be % or less of the cash distributed withrespect to that period. We anticipate that after the taxable year ending , the ratio of allocable taxable income to cash distributions to the unitholders willincrease. Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units of Atlas because remedialallocations of deductions to us from Atlas will be very limited and our ownership of incentive distribution rights will cause more taxable income to be allocatedto us from Atlas. Moreover, if Atlas is successful in increasing distributable cash flow over time, our income allocations from incentive distribution rights willincrease, and, therefore, our ratio of taxable income to cash distributions will further increase. These estimates are based upon the assumption that current rate ofdistributions from Atlas will approximate the amount required to make the initial quarterly distribution of $0.225 per common unit on all units and otherassumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among otherthings, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax lawand tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to becorrect. The actual ratio of taxable income could be higher or lower than our estimate of %, and any differences could be material and could materially affectthe value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will begreater than % with respect to the period described above if:

• Atlas’ gross income from operations exceeds the amount required to make the minimum quarterly distribution on all Atlas’ units, yet Atlas onlydistributes the minimum quarterly distribution on all its units; or

• Atlas makes a future offering of common units and uses the proceeds of the offering in a manner that does not produce substantial additional deductionsduring the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible fordepreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicableto Atlas’ assets at the time of this offering.

Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis willbe increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, bydistributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures thatare not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to the generalpartner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “Material Tax Consequences—Disposition ofCommon Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporateunitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax−exemptorganizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder mustrecapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Lossesdisallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount,whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses

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that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gainpreviously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourseliabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to theunitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increasesor decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely−held corporations and personal service corporations can deductlosses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent ofthe taxpayer’s income from those passive activities. As a general rule, the passive loss limitations are applied separately with respect to each publicly tradedpartnership. However, the application of the passive loss limitations to tiered publicly traded partnerships is uncertain. We will take the position that any passivelosses we generate that are reasonably allocable to our investment in Atlas will only be available to offset our passive income generated in the future that isreasonably allocable to our investment in Atlas and will not be available to offset income from other passive activities or investments, including otherinvestments in private businesses or investments we may make in other publicly traded partnerships. Moreover, because the passive loss limitations are appliedseparately with respect to each publicly traded partnership, any passive losses we generate will not be available to offset your income from other passiveactivities or investments, including your investments in other publicly traded partnerships, such as Atlas, or salary or active business income. Further, your shareof our net income may be offset by any suspended passive losses from your investment in us, but may not be offset by our current or carryover losses from otherpassive activities, including those attributable to other publicly traded partnerships. Passive losses that are not deductible because they exceed a unitholder’sshare of income we generate may be deducted in full when he disposes of his entire investment in us and Atlas in a fully taxable transaction with an unrelatedparty.

The IRS could take the position that for purposes of applying the passive loss limitation rules to tiered publicly traded partnerships, such as Atlas and us, therelated entities are treated as one publicly traded partnership. In that case, any passive losses we generate would be available to offset income from yourinvestments in Atlas. However, passive losses that are not deductible because they exceed a unitholder’s share of income we generate would not be deductible infull until a unitholder disposes of his entire investment in both us and Atlas in a fully taxable transaction with an unrelated party.

The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

Limitations on Interest Deductions

The deductibility of a non−corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.”Investment interest expense includes:

• interest on indebtedness properly allocable to property held for investment;

• our interest expense attributed to portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchaseor carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive lossrules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributableto the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as

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investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity−Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or the general partner or anyformer unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whosebehalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as adistribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic taxcharacteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwiseapplicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of taxon behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated to the unitholders in accordance with their percentage interestsin us. If we have a net loss for the entire year, that loss will be allocated to the unitholders in accordance with their percentage interests in us to the extent of theirpositive capital accounts and, second, to the general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets attime of this offering, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing common units in thisoffering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In addition, items ofrecapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recaptureincome in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in thecreation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in such amount and manneras is needed to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference betweena partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis ofContributed Property, referred to in this discussion as the “Book−Tax Disparity,” will generally be given effect for federal income tax purposes in determining apartner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an itemwill be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

• his relative contributions to us;

• the interests of all the partners in profits and losses;

• the interest of all the partners in cash flow; and

• the rights of all the partners to distributions of capital upon liquidation.Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election” and“—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect forfederal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

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Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would nolonger be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As aresult, during this period:

• any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

• any cash distributions received by the unitholder as to those units would be fully taxable; and

• all of these distributions would appear to be ordinary income.Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short saleof common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged tomodify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studyingissues relating to the tax treatment of short sales of partnership interests. Please also read “Material Tax Consequences—Disposition of CommonUnits—Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternativeminimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of theexemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to theimpact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

In general, the highest effective United States federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax ratefor net capital gains of an individual is currently 15.0% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election willgenerally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect hispurchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaserand not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share ofour tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we will adopt), a portion of theSection 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built−in gain. UnderTreasury Regulation Section 1.167(c)−1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the InternalRevenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight−line method or the 150%declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if thatposition is not consistent with these Treasury Regulations. Please read “Material Tax Consequences—Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no controlling authority on this issue, we intend todepreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of anyunamortized

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Book−Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the commonbasis of the property, or treat that portion as non−amortizable to the extent attributable to property the common basis of which is not amortizable. This method isconsistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)−1(a)(6),which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value inexcess of the unamortized Book−Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that thisposition cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month wouldreceive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they hadpurchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than wouldotherwise be allowable to some unitholders. Please read “Material Tax Consequences—Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediatelyprior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletiondeductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s taxbasis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the unitsmay be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case ofa transfer of an interest in us if we have a substantial built in loss immediately after the transfer or if we distribute property and have a substantial basis reduction.Generally, a built in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters.For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seekto reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets or the tangible assets owned by Atlas to goodwill instead.Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannotassure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced ordisallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefitof the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may beallocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending September 30 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be requiredto include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder whohas a taxable year ending on a date other than September 30 and who disposes of all of his units following the close of our taxable year but before the close of histaxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include inincome for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “Material Tax Consequences —Disposition ofCommon Units—Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets and Atlas’ assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on thedisposition of these assets. The tax basis of our assets we own at the time of this offering will be greater to the extent such assets have been recently

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acquired. The federal income tax burden associated with the difference between the fair market value of our assets and Atlas’ assets and their tax basisimmediately prior to this offering will be borne by our existing unitholders. Please read “Material Tax Consequences—Tax Consequences of UnitOwnership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early yearsafter assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal RevenueCode.

If we or Atlas dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount ofdepreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain.Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own or Atlas owns will likely be required to recapturesome or all of those deductions as ordinary income upon a sale of his interest in us. Please read “Material Tax Consequences—Tax Consequences of UnitOwnership—Allocation of Income, Gain, Loss and Deduction” and “Material Tax Consequences—Disposition of Common Units—Recognition of Gain orLoss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination.There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may notbe amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and theinitial tax bases, of our assets and Atlas’ assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we willmake many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding onthe IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss ordeductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest andpenalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. Aunitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourseliabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a taxliability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, ineffect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is lessthan his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year willgenerally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at amaximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the InternalRevenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own or Atlasowns. The term “unrealized receivables” includes potential recapture items, including depreciation

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recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the saleof a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and acapital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may onlybe used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted taxbasis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests soldusing an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relationto the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with anascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will beunable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specificcommon units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common unitstransferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase ofadditional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling andapplication of the regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating ataxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair marketvalue, if the taxpayer or related persons enter(s) into:

• a short sale;

• an offsetting notional principal contract; or

• a futures or forward contract with respect to the partnership interest or substantially identical property.Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to thepartnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest orsubstantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positionsthat have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among theunitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month,which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinarycourse of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholdertransferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations as there is no controlling authority on the issue. Accordingly, Vinson & ElkinsL.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the TreasuryRegulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. Weare authorized to revise our method of

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allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future TreasuryRegulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will beallocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units other than through a broker generally is required to notify us in writing of that sale within 30 days after the sale (or, ifearlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is generally required to notify us in writingof that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of that transactionand to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties.However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange througha broker.

Constructive Termination

We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits withina 12−month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable yearother than a fiscal year ending September 30, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable inhis taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if wewere unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any taxlegislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser ofthese units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory andregulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)−1(a)(6). Any non−uniformity could have a negativeimpact on the value of the units. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent ofany unamortized Book−Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life appliedto the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable,consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section1.167(c)−1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “Material Tax Consequences—Tax Consequences ofUnit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortizedBook−Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonablybe taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation andamortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased adirect interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise beallowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable.This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders.If we choose

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not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic taxcharacteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of unitsmight be increased without the benefit of additional deductions. Please read “Material Tax Consequences—Disposition of Common Units—Recognition of Gainor Loss.”

Tax−Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax−exempt organizations, non−resident aliens, foreign corporations and other foreign persons raises issuesunique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, aresubject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax−exempt organization will beunrelated business taxable income and will be taxable to them.

Non−resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of theownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federalincome tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at thehighest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identificationnumber from the IRS and submit that number to our transfer agent on a Form W−8BEN or applicable substitute form in order to obtain credit for thesewithholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to theUnited States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in theforeign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced oreliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, thistype of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a published ruling of the IRS, the IRS has taken a position that a foreign unitholder who sells or otherwise disposes of a unit will be subject to federalincome tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of theforeign unitholder. Because a foreign unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this rulinga foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or disposition of units.Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in valueof the units during the five−year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time ofthe sale or disposition.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K−1, which describeshis share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we willtake various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss anddeduction. We cannot assure you that those positions will in all cases yield a result that conforms to the requirements of the Internal Revenue Code, TreasuryRegulations

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or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contendin court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s taxliability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as thoserelated to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and taxsettlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than inseparate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Thepartnership agreement names Atlas Pipeline Holdings GP, LLC as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute oflimitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1%profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax MattersPartner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if theTax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group ofunitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with aninterest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment ofthe item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is:

1. a person that is not a United States person;

2. a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

3. a tax−exempt entity;

(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well asthe amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information onunits they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by theInternal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the informationfurnished to us.

Accuracy−Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligenceor disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal

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Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and thatthe taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the taxrequired to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion isattributable to a position adopted on the return:

(a) for which there is, or was, “substantial authority;” or

(b) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.If any item of income, gain, loss or deduction included in the distributive shares of unitholders for a given year might result in an “understatement” of income forwhich no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficientinformation for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability forpenalties. More stringent rules apply to “tax shelters,” which we do not believe include us.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of theamount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to asubstantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correctvaluation, the penalty imposed increases to 40%.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to theIRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publiclyidentified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2.0 million. Our participation in a reportable transactioncould increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read“—Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject tothe following provisions of the American Jobs Creation At of 2004:

• accuracy related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at“—Accuracy Related Penalties.”

• for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductability of interest on any resulting tax liability; and

• in the case of a listed transaction, an extended statute of limitations.We do not expect to engage in any reportable transactions.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, andestate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we or Atlas do business or own property or in which you are aresident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment inus. We or Atlas will initially own property or do business in Arkansas, New York, Ohio, Oklahoma, Pennsylvania and Texas, and each impose a personal incometax on individuals as well as an income tax on corporations and other entities, other than Texas. We may also own property or do business in other jurisdictionsin the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below thefiling

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and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or ownproperty and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the yearincurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold apercentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater orless than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an incometax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “Material TaxConsequences—Tax Consequences of Unit Ownership—Entity−Level Collections.” Based on current law and our estimate of our future operations, the generalpartner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us.Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, itis the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him.Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN ATLAS PIPELINE HOLDINGS L.P. BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciaryresponsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes theterm “employee benefit plan” includes, but is not limited to, qualified pension, profit−sharing and stock bonus plans, Keogh plans, simplified employee pensionplans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be givento:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

• whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

• whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after−tax investment return.The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment inus is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of anemployee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualifiedpersons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether theplan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatoryrestrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interestswould be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among otherthings:

(a) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investorsindependent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital eitherdirectly or through a majority−owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held bythe employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the InternalRevenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Lehman Brothers Inc. is acting as sole book running manager. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registrationstatement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its namebelow:

Underwriters

Number ofcommon

units

Lehman Brothers Inc.Total 3,600,000

The underwriting agreement provides that the underwriters’ obligation to purchase common units depends on the satisfaction of the conditions contained in theunderwriting agreement including:

• the obligation to purchase all of the common units offered hereby, if any of the common units are purchased;

• the representations and warranties made by us to the underwriters are true;

• there is no material change in the financial markets; and

• we deliver customary closing documents to the underwriters.Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both noexercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to thepublic and the amount the underwriters pay to us for the common units.

No exercise Full exercise

Per Unit $ $Total $ $

Lehman Brothers Inc. has advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of thisprospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per unit. Theunderwriters may allow, and the selected dealers may re−allow, a discount from the concession not in excess of $ per unit to other dealers. After the offering,Lehman Brothers Inc. may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be $ (exclusive of underwriting discounts and commissions).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to anaggregate of 540,000 common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriterssell more than 3,600,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject tocertain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s percentage underwriting commitment in theoffering as indicated in the table at the beginning of this Underwriting section. To the extent the underwriters purchase our common units pursuant to the exerciseof this option, we will redeem an equal amount of common units from Atlas America.

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Lock−Up Agreements

We, our affiliates that own common units, and the directors and executive officers of our general partner have agreed that, without the prior written consent ofLehman Brothers Inc., we and they will not directly or indirectly, offer, pledge, announce the intention to sell, sell, contract to sell, sell an option or contract topurchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of any common units or anysecurities that may be converted into or exchanged for any common units, enter into any swap or other agreement that transfers, in whole or in part, any of theeconomic consequences of ownership of the common units, make any demand for or exercise any right or file or cause to be filed a registration statement withrespect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or publiclydisclose the intention to do any of the foregoing for a period of 180 days from the date of this prospectus other than permitted transfers.

The 180−day restricted period described in the preceding paragraph will be extended if:

• during the last 17 days of the 180−day restricted period we issue an earnings release or announce material news or a material event; or

• prior to the expiration of the 180−day restricted period, we announce that we will release earnings results during the 16−day period beginning on thelast day of the 180−day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18−day period beginning on the issuance ofthe earnings release or the announcement of the material news or material event.

Lehman Brothers Inc., in its sole discretion, may release the common units and other securities subject to the lock−up agreements described above in whole or inpart at any time with or without notice. When determining whether or not to release common units and other securities from lock−up agreements, LehmanBrothers Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which therelease is being requested and market conditions at the time.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price will be negotiated between the representatives andus. In determining the initial public offering price of our common units, the representatives will consider:

• the history and prospects for the industry in which we compete;

• our financial information;

• the ability of our management and our business potential and earning prospects;

• the prevailing securities markets at the time of this offering; and

• the recent market prices of, and the demand for, publicly traded common units of generally comparable companies.Indemnification

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection withthe directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Directed Unit Program

At our request, the underwriters have reserved for sale at the initial public offering price up to common units offered hereby for officers, directors, employeesand certain other persons associated with us. The number of common units available for sale to the general public will be reduced to the extent such

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persons purchase such reserved common units. Any reserved common units not so purchased will be offered by the underwriters to the general public on thesame basis as the other common units offered hereby.

Stabilization, Short Positions and Penalty Bids

The underwriters may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for thepurpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934:

• Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

• A short position involves a sale by the underwriters of common units in excess of the number of common units the underwriters are obligated topurchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position.In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units theyare obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additionalcommon units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchaseadditional common units. The underwriters may close out any short position by either exercising their option to purchase additional common unitsand/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters willconsider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchasecommon units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters areconcerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investorswho purchase in the offering.

• Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to coversyndicate short positions.

• Penalty bids permit Lehman Brothers Inc. to reclaim a selling concession from a syndicate member when the common units originally sold by thesyndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our commonunits or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price thatmight otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may bediscontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described abovemay have on the price of the common units. In addition, neither we nor any of the underwriters make representation that the underwriters will engage in thesestabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwritersand/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and,depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agreewith us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made bythe underwriters on the same basis as other allocations.

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Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in anyother web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms apart, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and shouldnot be relied upon by investors.

NYSE

We will apply to list our common units for quotation on The New York Stock Exchange under the symbol “ .”

Discretionary Sales

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offeredby them.

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country ofpurchase, in addition to the offering price listed on the cover page of this prospectus.

Relationships

The underwriters may in the future perform investment banking and advisory services for us from time to time for which they may in the future receivecustomary fees and expenses. The underwriters may, from time to time, engage in transactions with or perform services for us in the ordinary course of theirbusiness.

Lehman Brothers Inc. and its related entities have engaged and may engage in commercial and investment banking transactions with Atlas, Atlas America, itsgeneral partner and us in the ordinary course of their business. Lehman Brothers Inc. has received customary compensation and expenses for these commercialand investment banking transactions. Lehman Brothers Inc. acted as the exclusive financial advisor to Energy Spectrum Capital Partners, which held acontrolling interest in Spectrum, in the solicitation of proposals for a potential sale transaction of Spectrum. In addition, Lehman Brothers Inc. acted as theexclusive financial advisor to OGE Energy Corporation in the solicitation of proposals for a potential sale transaction of Enogex Arkansas Pipeline Corporation,which became Atlas Arkansas. Lehman Brothers Inc., acted as an underwriter in our follow−on offering in July 2004 and in November 2005.

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VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., New York, New York, and for the underwriters by Baker Botts L.L.P.,Houston, Texas.

EXPERTS

The consolidated financial statements of Atlas Pipeline Partners GP, LLC as of December 31, 2003 and 2004 and for each of the three years in the period endedDecember 31, 2004; the balance sheet of Atlas Pipeline Holdings, L.P. as of December 31, 2005; the balance sheet of Atlas Pipeline Holdings GP, LLC as ofDecember 31, 2005; the financial statements of ETC Oklahoma Pipeline, Ltd. as of August 31, 2003 and 2004 and for the year ended August 31, 2004 and for theeleven month period ended August 31, 2003; the financial statements of the Elk City System (a division of Aquila Gas Pipeline Corporation) for the year endedSeptember 30, 2002, the financial statements of Spectrum Field Services, Inc. as of December 31, 2002 and 2003 and for each of the three years in the periodended December 31, 2003, have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their reports with respectthereto, herein in reliance upon the authority of such firm as experts in accounting and auditing.

The consolidated financial statements of Enogex Arkansas Pipeline Corporation at December 31, 2004 and 2003, and for each of the two years in the periodended December 31, 2004, have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon and included therein. Suchconsolidated financial statements are included herein in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the Commission, a registration statement on Form S−l regarding the common units. Thisprospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by thisprospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statementof which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by theCommission at 100 F Street, N.E. Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates bywriting to the public reference room maintained by the Commission at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information onthe operation of the public reference room by calling the Commission at l−800−SEC−0330. The Commission maintains a web site on the Internet athttp://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the Commission’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing ourunaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

FORWARD−LOOKING STATEMENTS

Some of the information in this prospectus may contain forward−looking statements. These statements can be identified by the use of forward−lookingterminology including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss plans, strategies,events, future expectations, contain projections of results of operations or of financial condition, or state other “forward−looking” information that we expect willor may occur in the future. These forward−looking statements involve risks and uncertainties. When considering these forward−looking statements, you shouldkeep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could causeour actual results to differ materially from those contained in any forward−looking statement.

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Specific factors could cause our actual results to differ materially from those contained in any forward−looking statement. These factors include, but are notlimited to:

• increased competition in natural gas and NGL markets and Atlas’ ability to respond to the competition;

• fluctuations in natural gas and NGL prices, which could adversely affect Atlas’ operating results and cash flows;

• decreased availability of local, intrastate and interstate transportation systems;

• increased expenses Atlas incurs in providing its gathering services;

• technical advances in fuel economy and energy generation devices;

• risks associated with the expansion of Atlas’s operations and properties;

• customer bankruptcies and/or cancellations or breaches of existing contracts;

• customer delays or defaults in making payments;

• fluctuations in natural gas and NGL demand, prices and availability due to labor and transportation costs and disruptions, equipment availability,governmental regulations and other factors;

• Atlas’ productivity levels and margins that Atlas earns on its coal sales;

• greater than expected shortage of skilled labor;

• any unanticipated increases in labor costs, adverse changes in work rules, or unexpected cash payments associated with workers’ compensation claims;

• any unanticipated increases in transportation costs and risk of transportation delays or interruptions;

• greater than expected environmental regulation, costs and liabilities;

• results of litigation; and

• difficulty obtaining commercial property insurance, and risks associated with Atlas’ participation (excluding any applicable deductible) in Atlas’commercial insurance property program.

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially fromthose described in any forward−looking statement. When considering forward−looking statements, you should also keep in mind the risk factors described in“Risk Factors.” The risk factors could also cause our actual results to differ materially from those contained in any forward−looking statement. We disclaim anyobligation to update the above list or to announce publicly the result of any revisions to any of the forward−looking statements to reflect future events ordevelopments.

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INDEX TO FINANCIAL STATEMENTS

PageAtlas Pipeline Holdings, L.P.Unaudited Pro Forma Consolidated Financial Statements:

Introduction F−3Unaudited Pro Forma Consolidated Balance Sheet at September 30, 2005 F−6Unaudited Pro Forma Consolidated Statements of Income for the Year Ended December 31, 2004 and the Nine Months Ended September30, 2005 F−7Notes to Unaudited Pro Forma Consolidated Financial Statements F−9

Atlas Pipeline Holdings, L.P.Audited Balance Sheet:

Report of Independent Registered Public Accounting Firm F−11Balance Sheet at December 31, 2005 F−12Note to Balance Sheet F−13

Atlas Pipeline Holdings GP, LLCAudited Balance Sheet:

Report of Independent Registered Public Accounting Firm F−14Balance Sheet at December 31, 2005 F−15Note to Balance Sheet F−16

Atlas Pipeline Partners GP, LLCAudited Consolidated Financial Statements:

Report of Independent Registered Public Accounting Firm F−17Consolidated Balance Sheets at December 31, 2003 and 2004 and September 30, 2005 (unaudited) F−18Consolidated Statements of Income for the Years Ended December 31, 2002, 2003 and 2004 and the Nine Months Ended September 30,2004 and 2005 (unaudited) F−19Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2002, 2003 and 2004 and the Nine MonthsEnded September 30, 2004 and 2005 (unaudited) F−20Consolidated Statements of Owner’s Equity (Deficit) F−21Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2003 and 2004 and the Nine Months Ended September30, 2004 and 2005 (unaudited) F−22Notes to Consolidated Financial Statements F−23

Enogex Arkansas Pipeline CorporationAudited Financial Statements:

Report of Independent Auditors F−43Consolidated Balance Sheets as of December 31, 2004 and 2003 F−44Consolidated Statements of Income for the Year Ended December 31, 2004 and 2003 F−46Consolidated Statements of Retained Earnings (Deficit) for the Year Ended December 31, 2004 and 2003 F−47Consolidated Statements of Cash Flows for the Year Ended December 31, 2004 and 2003 F−48Notes to Consolidated Financial Statements F−49

Enogex Arkansas Pipeline CorporationUnaudited Financial Statements:

Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004 F−55Consolidated Statements of Income for the Nine Months Ended September 30, 2005 and 2004 F−57Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004 F−58Notes to Consolidated Financial Statements F−59

ETC Oklahoma Pipeline, Ltd.Audited Financial Statements:

Report of Independent Registered Public Accounting Firm F−63Balance Sheets as of August 31, 2004 and 2003 F−64Income Statements for the Twelve Months ended August 31, 2004 and the Eleven Months Ended August 31, 2003 F−65Statements of Partners’ Capital for the Twelve Months Ended August 31, 2004 and 2003 F−66Statement of Cash Flows for the Twelve Months Ended August 31, 2004 and the Eleven Months Ended August 31, 2003 F−67Notes to Financial Statements F−68

ETC Oklahoma Pipeline, Ltd.Unaudited Financial Statements:

Balance Sheet as of February 28, 2005 F−74Income Statements for the Six Months Ended February 28, 2005 and February 29, 2004 F−75Statements of Cash Flows for the Six Months Ended February 28, 2005 and February 29, 2004 F−76Notes to Financial Statements F−77

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INDEX TO FINANCIAL STATEMENTS (Continued)

PageThe Elk City System (a division of Aquila Gas Processing Corporation)Audited Financial Statements:

Report of Independent Registered Public Accounting Firm F−80Carve−Out Statement of Income and Changes in Parent’s Equity in Division for the Year Ended September 30, 2002F−81Carve−Out Statement of Cash Flow for the Year Ended September 30, 2002 F−82Notes to Carve−Out Financial Statements F−83

Spectrum Field Services, Inc.Audited Financial Statements:

Report of Independent Certified Public Accountants F−88Balance Sheets as of December 31, 2003 and 2002 F−89Statement of Operations for the Years Ended December 31, 2003, 2002, and 2001 F−90Statements of Comprehensive Income (Loss) as of December 31, 2003, 2002 and 2001 F−91Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001 F−92Statements of Cash Flows for the Years Ended December 31, 2003, 2002, and 2001 F−94Notes to Financial Statements F−95

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ATLAS PIPELINE HOLDINGS, L.P.UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Unless indicated otherwise, the terms “our,” “we,” “us,” “Atlas Holdings” and other similar language refer to Atlas Pipeline Holdings, L.P. We own and controlAtlas Pipeline Partners GP, LLC, which is the general partner of Atlas Pipeline Partners, L.P., a publicly traded limited partnership (“Atlas”). Since we own andcontrol Atlas’ general partner, we reflect our ownership interest in Atlas on a consolidated basis and our financial results are combined with those of Atlas and itsgeneral partner.

The following unaudited pro forma financial statements reflect our historical results as adjusted on a pro forma basis to give effect to Atlas’ April 2004, July2004, June 2005 and November 2005 offerings of common units, the December 2005 issuance of Atlas’ senior unsecured notes, the completion of the Spectrum,Elk City and NOARK acquisitions and this offering. The acquisition and other adjustments are described in the notes to the unaudited pro forma financialstatements. The unaudited pro forma financial statements and accompanying notes should be read together with “Selected Historical Financial and OperatingData,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our historical financial statements and related notes and thehistorical financial statements and related notes of Spectrum, Elk City and its predecessor and Enogex Arkansas Pipeline Corporation included in this registrationstatement.

We accounted for the NOARK acquisition and the acquisitions of Spectrum and Elk City in the unaudited pro forma financial statements using the purchasemethod of accounting in accordance with the guidance of Statement of Financial Accounting standards No. 141, “Business Combinations.” For purposes ofdeveloping the unaudited pro forma financial information, we have allocated the purchase prices to Spectrum’s, Elk City’s, and NOARK’s gas gathering,processing and/or transmission facilities based on their fair market value.

Our summary unaudited pro forma balance sheet information reflects the following transactions as if they occurred as of September 30, 2005:

• the NOARK acquisition, which occurred on October 31, 2005, for consideration of $165.3 million, including estimated transaction costs plus $10.2million for working capital adjustments and $2.3 million of estimated transaction costs, and the redemption of the portion of the NOARK 7.15% notesseverally guaranteed by Atlas Arkansas;


• Atlas’ public offering of 2,700,000 common units, which was completed in November 2005, and 330,000 additional underwriter option units, whichwas completed in December 2005, each at a public offering price of $42.00 per common unit, the net proceeds of which were used principally to repayindebtedness incurred in connection with the NOARK acquisition;

• Atlas’ issuance of $250.0 million of 8.125% senior unsecured notes in a private placement on December 20, 2005, the net proceeds of which were usedprincipally to repay indebtedness under its credit facility; and

• this offering and the application of the net proceeds as described under “Use of Proceeds.”The unaudited pro forma statement of income information for the year ended December 31, 2004 reflects the following transactions as if they occurred as ofJanuary 1, 2004:

• Atlas’ public offering of 750,000 common units, which was completed in April 2004 at a public offering price of $36.00 per common unit, the netproceeds of which were used principally to repay indebtedness under Atlas’ then existing credit facility;

• the Spectrum acquisition, which occurred in July 2004, for total consideration of $141.6 million, including the payment of income taxes due as a resultof the transaction and other related transaction costs;

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• Atlas’ public offering of 2,100,000 common units, which was completed in July 2004 at a public offering price of $34.76 per common unit, the netproceeds of which were used principally to repay indebtedness incurred in connection with the Spectrum acquisition;



• Atlas’ public offering of 2,300,000 common units, which was completed in June 2005 at a public offering price of $41.95 per common unit, the netproceeds of which were used principally to repay indebtedness incurred in connection with the Elk City acquisition;



• Atlas’ public offering of 2,700,000 common units, which was completed in November 2005, and 330,000 additional underwriter option units, whichwas completed in December 2005, each at a public offering price of $42.00 per common unit, the net proceeds of which were principally used to repayindebtedness incurred in connection with the NOARK acquisition;



The unaudited pro forma statement of income information for the nine months ended September 30, 2005 reflects the following transactions as if they occurredas of January 1, 2005:



• Atlas’ public offering of 2,300,000 common units, which was completed in June 2005, at a public offering price of $41.95 per common unit, the netproceeds of which were principally used to repay indebtedness incurred in connection with the Elk City acquisition;



• Atlas’ public offering of 2,700,000 common units, which was completed in November 2005, and 330,000 additional underwriter option units, whichwas completed in December 2005, each at a public offering price of $42.00 per common unit, the net proceeds of which were used principally to repayindebtedness incurred in connection with the NOARK acquisition;

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Elk City’s historical fiscal year ended August 31, 2004 is not within 93 days of our fiscal year end. Accordingly, for pro forma purposes, statement of incomeinformation for the year ended December 31, 2004 is based on Elk City’s historical financial results for the twelve months ended November 30, 2004 and wascreated by subtracting the quarter ended November 30, 2003 from Elk City’s income statement for the year ended August 31, 2004 and adding the quarter endedNovember 30, 2004. For our pro forma statement of income information for the nine months ended September 30, 2005, we included Elk City’s incomestatement for the three months ended February 28, 2005. Elk City was included within our historical results for the nine months ended September 30, 2005 fromits date of acquisition on April 14, 2005.

The unaudited pro forma balance sheet and the pro forma statements of income were derived by adjusting historical financial statements of Atlas Pipeline GP.However, our management believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. Theunaudited pro forma financial data presented are for informational purposes only and are based upon available information and assumptions that we believe arereasonable under the circumstances. You should not construe the unaudited pro forma financial data as indicative of the combined financial position or results ofoperations that we, Atlas Pipeline GP, Atlas, Spectrum, Elk City and NOARK would have achieved had the transactions been consummated on the datesassumed. Moreover, they do not purport to represent our, Atlas’, Atlas Pipeline GP’s, Spectrum’s, Elk City’s or NOARK’s combined financial position or resultsof operations for any future date or period.

The financial data below should be read together with, and are qualified in their entirety by reference to, Atlas Pipeline GP’s historical consolidated and proforma combined financial statements and the accompanying notes, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,”and the historical consolidated financial statements and the accompanying notes of Spectrum, Elk City and its predecessor and Enogex Arkansas Pipeline, eachof which is set forth elsewhere in this prospectus. The pro forma data is not necessarily reflective of what our results would actually have been had thetransactions actually occurred on the indicated date, nor do they reflect what may actually occur in the future.

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ATLAS PIPELINE HOLDINGS, L.P.PRO FORMA CONSOLIDATED BALANCE SHEET (UNAUDITED)

SEPTEMBER 30, 2005(in thousands)

HistoricalAtlas

PipelineGP

HistoricalNOARK Adjustments

AtlasNovember

2005 EquityOffering

Adjustments

Atlas SeniorNotes

OfferingAdjustments

ProForma

AtlasPipelineHoldingsEquity

Offering

ProForma,

asadjusted

ASSETSCURRENT ASSETS:Cash and cash equivalents $ 12,035 $ 14,502 $ 178,000 (a)$ 120,933 (e)$ 243,125 (f) $ 29,338 $ 79,152 (g)$ 29,338

(177,757)(a) (120,933) (e) (240,567)(f) (79,152)(g)Accounts receivable — affiliates 4,418 7,236 (5,145)(b) — — 6,509 — 6,509

Accounts receivable 41,289 785 5,145 (b) — — 47,219 — 47,219Current portion of hedge asset 14,993 — — — — 14,993 — 14,993Prepaid expenses and other currentassets 1,595 324 — — — 1,919 — 1,919

Total current assets 74,330 22,847 243 — 2,558 99,978 — 99,978PROPERTY, PLANT ANDEQUIPMENT 324,517 146,509 32,006 (d) — — 503,032 — 503,032Less — accumulated depreciation (19,813) (20,593) — — — (40,406) — (40,406)

Net property, plant and equipment 304,704 125,916 32,006 — — 462,626 — 462,626MINORITY INTEREST IN NOARKASSETS — 3,359 40,544 (d) — — 43,903 — 43,903

LONG−TERM HEDGE ASSET 5,970 — — — — 5,970 — 5,970INTANGIBLES, NET 12,398 — — — — 12,398 — 12,398GOODWILL 80,201 — — — — 80,201 — 80,201OTHER ASSETS 6,855 1,532 (425)(c) — 6,875 (f) 17,237 — 17,237

2,400 (a)

$484,458 $153,654 $ 74,768 $ — $ 9,433 $722,313 $ — $722,313

LIABILITIES AND OWNERS’EQUITY

CURRENT LIABILITIES:Current portion of NOARK long−termdebt $ — $ 1,200 $ — $ — $ — $ 1,200 $ — $ 1,200Current portion of other long−termdebt 63 800 (800)(d) — — 63 — 63

Accrued liabilities 6,360 3,037 — — — 9,397 — 9,397Current portion of hedge liability 37,663 — — — — 37,663 — 37,663

Accrued producer liabilities 32,543 — — — — 32,543 — 32,543Accounts payable 7,257 6,468 1,551 (b) — — 15,276 — 15,276Accounts payable — affiliates — 1,551 (1,551)(b) — — — — —

Total current liabilities 83,886 13,056 (800) — — 96,142 — 96,142

LONG−TERM HEDGE LIABILITY 29,962 — — — — 29,962 — 29,962

NOARK LONG−TERM DEBT — 38,400 — — — 38,400 — 38,400

SENIOR UNSECURED DEBT — — — — 250,000 (f) 250,000 — 250,000

SENIOR SECURED DEBT 183,582 25,600 178,000 (a) (120,933)(e) (240,567)(f) 82 — 82(25,600)(d)

MINORITY INTEREST 227,908 — (229)(a) 120,933(e) — 348,612 — 348,612

DEFERRED INCOME TAXES — 21,893 (21,893)(d) — — — — —

PARTNERS’ EQUITY:Partners’ equity 5,564 54,705 (54,705)(d) — — 5,559 79,152 (g) 5,559

(5)(a) (79,152)(g)

Accumulated other comprehensive loss (46,444) — — — — (46,444) — (46,444)

Total partners’ equity (40,880) 54,705 (54,710) — — (40,885) — (40,885)

$484,458 $153,654 $ 74,768 $ — $ 9,433 $722,313 $ — $722,313


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ATLAS PIPELINE HOLDINGS, L.P.PRO FORMA CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

FOR THE YEAR ENDED DECEMBER 31, 2004(in thousands, except per unit data)

HistoricalAtlas

PipelineGP

HistoricalSpectrum

HistoricalElk City


AtlasNovember

2005 EquityOffering

Adjustments

Atlas SeniorNotes

OfferingAdjustments

ProForma


Offering

ProForma,

asadjusted

REVENUE:Natural gas and liquids — thirdparties $ 72,109 $ 67,643 $ 11,376 $ 253 $ 166,544 (h) $ — $ — $ 317,925 $ — $ 317,925Natural gas and liquids — affiliates — — 123,975 55,763 (166,544) (h) — — 13,194 — 13,194Transportation and compression — third parties 76 — — 10,364 4,143 (h) — — 14,583 — 14,583Transportation and compression — affiliates 18,724 — — 11,119 (4,143) (h) — — 25,700 — 25,700Interest income and other 382 — — 329 — — — 711 — 711

Total revenue and other income 91,291 67,643 135,351 77,828 — — — 372,113 — 372,113

COSTS AND EXPENSES:Natural gas and liquids 58,707 54,565 118,537 55,019 — — — 286,828 — 286,828Plant operating 2,032 2,474 4,599 — — — — 9,105 — 9,105Transportation and compression 2,260 — — 4,434 — — — 6,694 — 6,694General and administrative 4,642 7,509 2,482 3,756 (2,482) (i) — — 10,378 — (s) 10,378

840 (i)(6,369) (j)

Gain on arbitration settlement, net (1,457) — — — — — — (1,457) — (1,457)Depreciation and amortization 4,471 1,638 2,153 3,249 (7,040) (k) — — 16,803 — 16,803

12,332 (k)Minority interest in Atlas 10,941 — — — 429 (l) — — 11,370 — 11,370Minority interest in NOARK — — — 492 — — — 492 — 492Interest 2,301 1,712 — 5,287 13,058 (m)(n) (5,782) (p) 9,121 (q) 26,385 — 26,385

688 (r) —Other (income) expense — (88,551) (3) — 89,109 (j) — — 555 — 555

Total costs and expenses 83,897 (20,653) 127,768 72,237 99,877 (5,782) 9,809 367,153 — 367,153

Income (loss) before income taxes 7,394 88,296 7,583 5,591 99,877 5,782 (9,809) 4,960 — 4,960Provision for income taxes — (32,319) — (2,162) 34,481 (o) — — — — —

Net income (loss) 7,394 55,977 7,583 3,429 (65,396) 5,782 (9,809) 4,960 — 4,960Premium on preferred unitredemption (400) — — — — — — (400) — (400)

Net income (loss) attributable toowners $ 6,994 $ 55,977 $ 7,583 $ 3,429 $ (65,396) $ 5,782 $ (9,809) $ 4,560 $ — $ 4,560

Net income per unit $ 0.22

Weighted average unitsoutstanding 21,100 (t)

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ATLAS PIPELINE HOLDINGS, L.P.PRO FORMA CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005(in thousands, except per unit data)

HistoricalAtlas

PipelineGP

HistoricalElk City


AtlasNovember

2005Equity

OfferingAdjustments

Atlas SeniorNotes

OfferingAdjustments

ProForma


Offering

ProForma,

asadjusted

REVENUE:Natural gas and liquids — third parties $ 218,268 $ 3,497 $ 237 $ 69,658 (h) $ — $ — $ 291,660 $ — $ 291,660Natural gas and liquids — affiliates — 37,235 42,125 (69,658) (h) — — 9,702 — 9,702Transportation and compression — thirdparties 54 — 8,174 1,999 (h) — — 10,227 — 10,227Transportation and compression — affiliates 16,447 — 6,955 (1,999) (h) — — 21,403 — 21,403Interest income and other 352 — 144 — — — 496 — 496

Total revenue and other income 235,121 40,732 57,635 — — — 333,488 — 333,488

COSTS AND EXPENSES:Natural gas and liquids 184,578 36,665 40,551 — — — 261,794 — 261,794Plant operating 7,242 1,363 — — — — 8,605 — 8,605Transportation and compression 2,169 — 3,547 — — — 5,716 — 5,716General and administrative 9,127 850 2,207 (850) (i) — — 11,544 — (s) 11,544

210 (i)Loss on arbitration settlement, net 138 — — — — — 138 — 138Depreciation and amortization 8,495 628 2,475 (3,103) (k) — — 12,809 — 12,809

4,314 (k)Minority interest in Atlas 7,240 — — (1,319) (l) — — 5,921 — 5,921Minority interest in NOARK — — 440 — — — 440 — 440Interest 8,478 — 3,654 9,062 (m)(n) (5,782) (p) 4,131 (q) 20,059 — 20,059

516 (r) —

Total costs and expenses 227,467 39,506 52,874 8,314 (5,782) 4,647 327,026 — 327,026

Income (loss) before income taxes 7,654 1,226 4,761 (8,314) 5,782 (4,647) 6,462 — 6,462Provision for income taxes — — (1,887) 1,887 (o) — — — — —

Net income (loss) $ 7,654 $ 1,226 $ 2,874 $ (6,427) $ 5,782 $ (4,647) $ 6,462 $ — $ 6,462

Net income per unit $ 0.31

Weighted average units outstanding 21,100 (t)

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ATLAS PIPELINE HOLDINGS, L.P.NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS

a. To reflect the application of $178,000,000 of borrowings under the Atlas credit facility for (a) payment to sellers and various acquisition costs of$175,123,000, which are allocated to the underlying assets and liabilities acquired as described in note d, (b) loan costs of $2,400,000, which will beamortized over the remaining term of the credit facility, (c) interest of $234,000, all of which relates to post−September 30, 2005 periods and charged hereinto owners’ equity, and (d) the remaining $243,000 to Atlas. We describe Atlas’ credit facility under “Other Indebtedness.”

b. To reclassify affiliated receivables and payables to third−party receivables and payables.

c. To remove $425,000 from Atlas’ other assets for acquisition costs previously paid or accrued and to include that amount within the purchase price allocationdescribed in note d below.

d. To reflect the allocation of the total purchase price for NOARK and various acquisition costs of $175,548,000 to the assets and liabilities acquired,consisting of $175,123,000 payment to seller and various acquisition costs as described in note a and the $425,000 of acquisition costs previously paid oraccrued as described in note c. The deferred tax liability and affiliated accounts payable were not assumed by Atlas and remain the responsibility of theseller. Also reflects the repayment of $26,400,000 of the 7.15% NOARK notes by the seller from the net proceeds from its sale of NOARK. This amountwas deposited into an escrow account for the purpose of repayment and retirement of this portion of the notes. The remaining outstanding portion of theNOARK notes is severally guaranteed by Southwestern, the 25% minority interest owner in NOARK. An acquisition adjustment has been included to adjustminority interest to reflect Southwestern’s interest in the NOARK notes.

e. To reflect net proceeds of $120,933,000, after estimated offering costs of $6,327,000, from the Atlas November 2005 sale of 2,700,000 common units andthe December 2005 sale of 330,000 additional underwriter option units, each at $42.00 per unit, principally used to repay borrowings under Atlas’ creditfacility.

f. To reflect net proceeds of $243,125,000, after estimated offering costs of $6,875,000, from Atlas’ December 2005 issuance of $250,000,000 of 8.125%senior unsecured notes due 2015, of which $240,567,000 was used to repay borrowings under Atlas’ credit facility, with the remaining $2,558,000 going toAtlas.

g. To reflect net proceeds from this offering of $79,152,000, after estimated offering costs of $7,248,000, assuming 3,600,000 common units at a price of$24.00 per unit, which will be distributed to Atlas America.

h. To reclassify affiliated revenue to third−party revenue.

i. To reflect the elimination of the overhead allocated to Elk City by its parent and its replacement with an overhead allocation to be made by us in accordancewith a new allocation agreement.

j. To reflect the elimination of non−cash compensation costs of $6,369,000 related to the vesting of stock options upon change of control and the gain of$89,109,000, in each case, on the sale of Spectrum’s assets to Atlas.

k. To reflect the adjustment to depreciation expense for Spectrum, Elk City and NOARK for the periods these entities were not included within our historicalresults based upon the cost of the acquired gas gathering and transmission facilities using depreciable lives ranging from 3 to 40 years and using thestraight−line method.

l. To reflect adjustment of the minority interest in the net income of Atlas as a result of the net effect of the pro forma statement of income adjustmentspreviously noted. The allocation of Atlas’ net income to minority interests is based upon the historical distributions received by its partners. It isimpracticable to determine what the cash available would have been on a pro forma basis. Accordingly, the allocation of Atlas’ net income to the minorityinterest owners reflects historical distributions.

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m. To reflect the adjustments to interest expense resulting from borrowings under Atlas’ credit facility to (a) finance the acquisitions of Spectrum, Elk City andNOARK, (b) reflect the net proceeds of the April 2004, July 2004, and June 2005 offerings of common units, and (c) reflect the repayment of the portion ofthe NOARK notes severally guaranteed by NOARK.

n. To reflect the amortization of deferred financing costs related to Atlas’ credit facility to finance the Elk City acquisition and the amendment to the creditfacility to finance the NOARK acquisition.

o. To reflect the elimination of federal and state income taxes following the conversion of Spectrum and Atlas Arkansas, which were both C−corporations, tolimited liability companies concurrent with their acquisition by Atlas.

p. To reflect the adjustment to interest expense resulting from the repayment of amounts outstanding under Atlas’ credit facility with proceeds from itsNovember 2005 equity offering.

q. To reflect the adjustment to interest expense resulting from the repayment of amounts outstanding under Atlas’ credit facility with proceeds from theirDecember 2005 issuance of senior unsecured notes.

r. To reflect the amortization of deferred financing costs related to the issuance of Atlas’ senior unsecured notes.

s. We estimate we will incur on−going general and administrative costs as a result of being a public entity, including, among other things, estimatedincremental accounting and audit fees, director fees, director and officer liability insurances expenses and other miscellaneous costs.

t. To reflect the adjustment of our outstanding limited partner units.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of DirectorsAtlas America, Inc.

We have audited the accompanying balance sheet of Atlas Pipeline Holdings, L.P. (the “Partnership”) as of December 31, 2005. This financial statement is theresponsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. The Partnership is not requiredto have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control overfinancial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on theeffectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financial statement. An audit also includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for ouropinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Atlas Pipeline Holdings, L.P. as ofDecember 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, OhioJanuary 3, 2006

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ATLAS PIPELINE HOLDINGS, L.P.BALANCE SHEET

DECEMBER 31, 2005

ASSETSCash $ 1,000

OWNERS’ EQUITYOwners’ equity $ 1,000

See accompanying note to balance sheet

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ATLAS PIPELINE HOLDINGS, L.P.NOTE TO BALANCE SHEET

DECEMBER 31, 2005

NATURE OF OPERATIONS

Atlas Pipeline Holdings, L.P. (the “Partnership”) is a Delaware limited partnership formed on December 15, 2005 to become the sole member of Atlas PipelinePartners GP, LLC, which is the managing general partner of Atlas Pipeline Partners, L.P. (“Atlas”), a publicly traded limited partnership. Atlas is a midstreamenergy service provider engaged in the transmission, gathering and processing of natural gas in the Mid−Continent and Appalachian regions of the United States.Our assets will consist of the following partnership interests in Atlas to be contributed to us by Atlas Pipeline Partners GP, LLC:

• The 100% ownership interest in Atlas Pipeline Partners GP, LLC, which owns a 2.0% general partner interest in Atlas;

• The incentive distribution rights in Atlas associated with the general partner interest, which we hold through our ownership interests in Atlas PipelinePartners GP, LLC; and

• 1,641,026 common limited partner units of Atlas, representing approximately 13.1% of the outstanding common limited partner units of Atlas, orapproximately 12.8% of Atlas’ partnership interests.

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Board of DirectorsAtlas America, Inc.

We have audited the accompanying balance sheet of Atlas Pipeline Holdings GP, LLC (the “Company”) as of December 31, 2005. This financial statement is theresponsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. The Company is not required tohave, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financialreporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectivenessof the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statement. An audit also includes assessing the accounting principles used and significant estimates madeby management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Atlas Pipeline Holdings GP, LLC as ofDecember 31, 2005, in conformity with accounting principles generally accepted in the United States of America.



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ATLAS PIPELINE HOLDINGS GP, LLCBALANCE SHEET

DECEMBER 31, 2005

ASSETSCash $ 1,000

OWNERS’ EQUITYOwners’ equity $ 1,000

See accompanying note to balance sheet

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ATLAS PIPELINE HOLDINGS GP, LLCNOTE TO BALANCE SHEET

DECEMBER 31, 2005

NATURE OF OPERATIONS

Atlas Pipeline Holdings GP, LLC (the “Company”) is a Delaware limited liability company formed on December 15, 2005 and is the general partner of AtlasPipeline Holdings, L.P., a Delaware limited partnership that was formed on December 15, 2005 to own Atlas Pipeline Partners GP, LLC, the general partner ofAtlas Pipeline Partners, L.P. (“Atlas”) and owner of 1,641,026 of Atlas’ common limited partner units. Atlas Pipeline Holdings GP, LLC’s general partnerinterest is fixed without any requirement for capital contributions in connection with additional unit issuances by Atlas Pipeline Holdings, L.P. because AtlasPipeline Holdings GP, LLC has no economic interest in Atlas Pipeline Holdings, L.P.

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Board of DirectorsAtlas Pipeline Partners GP, LLC

We have audited the accompanying consolidated balance sheets of Atlas Pipeline Partners GP, LLC and subsidiaries (the “Company”) as of December 31, 2003and 2004, and the related consolidated statements of income, comprehensive income, owners’ equity, and cash flows for each of the three years in the periodended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on thesefinancial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that weplan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not requiredto have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control overfinancial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on theeffectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for ouropinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Atlas PipelinePartners GP, LLC and subsidiaries as of December 31, 2003 and 2004 and the consolidated results of their operations and cash flows for each of the three yearsin the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.


Cleveland, OhioDecember 21, 2005

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ATLAS PIPELINE PARTNERS GP, LLC AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS

(in thousands)

December31,

September30,2003 2004 2005

(Unaudited)ASSETS

Current assets:Cash and cash equivalents $15,078 $ 18,214 $ 12,035Accounts receivable – affiliates 13,658 19,609 4,418Accounts receivable 12 13,729 41,289Current portion of hedge asset — 40 14,993Prepaid expenses 67 1,056 1,595

Total current assets 28,815 52,648 74,330

Property, plant and equipment, net 29,628 175,259 304,704

Long−term hedge asset — 14 5,970

Intangibles, net — — 12,398

Goodwill 2,305 2,305 80,201

Other assets 2,422 4,672 6,855

$63,170 $ 234,898 $ 484,458

LIABILITIES AND OWNERS’ EQUITY (DEFICIT)Current liabilities:Current portion of long−term debt $ — $ 2,303 $ 63Accrued liabilities 279 3,144 6,360Current portion of hedge liability — 1,959 37,663Accrued producer liabilities — 10,996 32,543Accounts payable 242 2,341 7,257Accounts payable – affiliates 1,673 — —Distribution payable 1,696 4,006 —

Total current liabilities 3,890 24,749 83,886

Long−term hedge liability — 722 29,962

Long−term debt, less current portion — 52,149 183,582

Minority interest 43,551 135,873 227,908

Commitments and contingencies — — —

Owners’ equity (deficit):Owners’ equity 15,729 22,723 5,564Accumulated other comprehensive loss — (1,318) (46,444)

Total owners’ equity (deficit) 15,729 21,405 (40,880)

$63,170 $ 234,898 $ 484,458

See accompanying notes to consolidated financial statements

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ATLAS PIPELINE PARTNERS GP, LLC AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF INCOME

(in thousands)

Nine Months EndedYears Ended December31, September30,

2002 2003 2004 2004 2005

(unaudited)Revenue:Natural gas and liquids $ — $ — $72,109 $30,048 $ 218,268Transportation and compression —

affiliates 10,581 15,563 18,724 13,292 16,447Transportation and compression —

third parties 79 88 76 52 54Interest income and other 7 98 382 282 352

Total revenue and other income 10,667 15,749 91,291 43,674 235,121

Costs and expenses:Natural gas and liquids — — 58,707 24,588 184,578Plant operating — — 2,032 931 7,242Transportation and compression 2,062 2,421 2,260 1,709 2,169General and administrative 1,274 854 3,561 2,180 7,762Compensation reimbursement — affiliates 208 808 1,081 721 1,365Depreciation and amortization 1,475 1,770 4,471 2,132 8,495Interest 250 258 2,301 1,202 8,478Minority interest 2,496 5,066 10,941 3,300 7,240Loss (gain) on arbitration settlement, net — — (1,457) 2,987 138

Total costs and expenses 7,765 11,177 83,897 39,750 227,467

Net income 2,902 4,572 7,394 3,924 7,654Premium on preferred unit redemption — — (400) (400) —

Net income attributable to owners $ 2,902 $ 4,572 $ 6,994 $ 3,524 $ 7,654


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ATLAS PIPELINE PARTNERS GP, LLC AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


2002 2003 2004 2004 2005

(unaudited)Net income $ 2,902 $ 4,572 $ 7,394 $ 3,924 $ 7,654Premium on preferred unit redemption — — (400) (400) —

Net income attributable to owners 2,902 4,572 6,994 3,524 7,654

Other comprehensive loss:Change in fair value of derivativeinstruments accounted for as hedges — — (1,320) (3,955) (49,507)

Add: reclassification adjustment forlosses in net income — — 2 27 4,381

— — (1,318) (3,928) (45,126)

Comprehensive income (loss) $ 2,902 $ 4,572 $ 5,676 $ (404) $(37,472)


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ATLAS PIPELINE PARTNERS GP, LLC AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OWNERS’ EQUITY (DEFICIT)

(in thousands)

AccumulatedOther

Owners’ Comprehensive Total Owners’Equity Loss Equity (Deficit)

Balance at January 1, 2002 $ 8,255 $ — $ 8,255

Net income 2,902 — 2,902

Balance at December 31, 2002 $ 11,157 $ — $ 11,157

Net income 4,572 — 4,572

Balance at December 31, 2003 $ 15,729 $ — $ 15,729

Other comprehensive loss — (1,318) (1,318)

Net income 6,994 — 6,994

Balance at December 31, 2004 $ 22,723 $ (1,318) $ 21,405

Other comprehensive loss (unaudited) — (45,126) (45,126)

Net income (unaudited) 7,654 — 7,654

Distribution to owners (unaudited) (24,813) — (24,813)

Balance at September 30, 2005 (unaudited) $ 5,564 $ (46,444) $ (40,880)


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ATLAS PIPELINE PARTNERS GP, LLC AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


2002 2003 2004 2004 2005

(unaudited)CASH FLOWS FROM OPERATING ACTIVITIES:Net income $ 2,902 $ 4,572 $ 6,994 $ 3,524 $ 7,654Adjustments to reconcile net income to net cash provided by operating activities:Minority interest in net income 2,496 5,066 10,941 3,300 7,240Distributions paid to minority interest limited partners in Atlas Pipeline (3,526) (5,040) (9,427) (5,589) (14,234)Depreciation and amortization 1,475 1,770 4,471 2,132 8,495Non−cash (gain) loss on derivative value — — (210) 585 (1,091)Non−cash compensation under long−term incentive plan — — 700 342 2,809Amortization of deferred finance costs 90 106 400 163 1,741Change in operating assets and liabilities, net of effects of acquisitions:Increase decrease in accounts receivable and prepaid expenses 799 827 5,444 1,320 (24,779)Increase (decrease) in accounts payable and accrued liabilities (82) 413 (3,264) 3,797 25,511(Increase) decrease in accounts receivable – affiliates (3,577) (3,075) (4,738) (90) 17,652

Net cash provided by operating activities 577 4,639 11,311 9,484 30,998

CASH FLOWS FROM INVESTING ACTIVITIES:Acquisitions — — (141,626) (141,564) (195,201)Capital expenditures (5,230) (7,635) (10,043) (4,419) (34,519)Other (1,519) (128) 255 (172)

Net cash used in investing activities (5,230) (9,154) (151,797) (145,728) (229,892)

CASH FLOWS FROM FINANCING ACTIVITIES:Borrowings under Atlas Pipeline credit facility 10,816 2,000 110,000 100,000 271,500Repayments under Atlas Pipeline credit facility (6,405) (8,500) (55,750) (40,000) (142,250)Net proceeds from issuance of Atlas Pipeline limited partner units — 25,182 93,119 93,114 91,720Distribution to owners — — — — (24,813)Net proceeds from sale of Atlas Pipeline preferred units — — 20,000 20,000 —Redemption of Atlas Pipeline preferred units — — (20,000) (20,000) —Other (61) (948) (3,747) (2,928) (3,442)

Net cash provided by financing activities 4,350 17,734 143,622 150,186 192,715

Net change in cash and cash equivalents (303) 13,219 3,136 13,942 (6,179)Cash and cash equivalents, beginning of period 2,162 1,859 15,078 15,078 18,214

Cash and cash equivalents, end of period $ 1,859 $15,078 $ 18,214 $ 29,020 $ 12,035


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ATLAS PIPELINE PARTNERS GP, LLC AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — NATURE OF OPERATIONS

Atlas Pipeline Partners GP, LLC (the “Company”) is a Delaware limited liability company formed in May 1999 to become the general partner of Atlas PipelinePartners, L.P. (the “Atlas Pipeline”). The Company is wholly−owned by Atlas America, Inc. and its affiliates (“Atlas America”), a publicly traded company(NASDAQ: ATLS).

Atlas Pipeline is a Delaware limited partnership formed in May 1999 to acquire, own and operate natural gas gathering systems previously owned by AtlasAmerica. Atlas Pipeline’s operations are conducted through subsidiary entities whose equity interests are owned by Atlas Pipeline Operating Partnership, L.P.(the “Operating Partnership”), a wholly−owned subsidiary of Atlas Pipeline. The Company, through its general partner interests in Atlas Pipeline and theOperating Partnership, owns a 2.0% general partner interest in the consolidated pipeline operations, through which it manages and effectively controls both AtlasPipeline and the Operating Partnership. The remaining 98.0% ownership interest in the consolidated pipeline operations consists of limited partner interests inAtlas Pipeline. At December 31, 2004, Atlas Pipeline had 5,563,659 common and 1,641,026 subordinated limited partnership units outstanding. In January 2005,these subordinated units, which are owned by the Company, were converted to common units as Atlas Pipeline met stipulated tests under the terms of itspartnership agreement allowing for such conversion. While the converted units are no longer subordinated to the rights of the common unitholders, these unitshave not yet been registered with the Securities and Exchange Commission and, therefore, their resale in the public market is subject to restrictions under theSecurities Act. At September 30, 2005, Atlas Pipeline had 9,505,016 common limited partnership units outstanding, including the 1,641,026 unregisteredcommon units held by the Company.

The Company, as general partner, manages the operations and activities of Atlas Pipeline and owes a fiduciary duty to Atlas Pipeline’s unitholders. TheCompany is liable, as general partner, for all of Atlas Pipeline’s debts (to the extent not paid from Atlas Pipeline’s assets), except for indebtedness or otherobligations that are made specifically nonrecourse to the general partner.

The Company does not receive any management fee or other compensation for its management of Atlas Pipeline. The Company and its affiliates are reimbursedfor expenses incurred on Atlas Pipeline’s behalf. These expenses include the costs of employee, officer, and managing board member compensation and benefitsproperly allocable to Atlas Pipeline and all other expenses necessary or appropriate to conduct the business of, and allocable to, Atlas Pipeline. The AtlasPipeline partnership agreement provides that the Company, as general partner, will determine the expenses that are allocable to Atlas Pipeline in any reasonablemanner in its sole discretion.

The accompanying unaudited consolidated balance sheet as of September 30, 2005 and the consolidated statements of income, comprehensive income, cashflows and owners’ equity for the nine months ended September 30, 2004 and 2005 are presented in accordance with accounting principles generally accepted inthe United States for interim reporting. In management’s opinion, all adjustments necessary for the fair presentation of the Company’s financial position, resultsof operations and cash flows for the periods presented have been made. The related disclosures as of September 30, 2005 and for the nine month periods endedSeptember 30, 2004 and 2005 are also unaudited.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of ConsolidationThe consolidated financial statements include the accounts of the Company, Atlas Pipeline, the Operating Partnership and the Operating Partnership’swholly−owned subsidiaries. The Partnership’s limited partner equity interests owned by third−parties at September 30, 2005 and December 31, 2003 and

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2004 are reflected as minority interests on the consolidated balance sheets. All material intercompany transactions have been eliminated.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with accounting principles generally accepted in the United States requiresmanagement to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities thatexist at the date of the Company’s consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reportingperiods. Actual results could differ from those estimates.

The natural gas industry principally conducts its business by processing actual transactions at the end of the month following the month of delivery.Consequently, the most current month’s financial results for the Company include estimated volumes and market prices. Differences between estimated andactual amounts are recognized in the following month’s financial results. Management believes that the operating results presented for the three years endedDecember 31, 2004 and for the nine months ended September 30, 2004 and 2005 represent actual results in all material respects (see Revenue Recognitionaccounting policy for further description).

Cash EquivalentsThe Company considers all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cashequivalents consist principally of temporary investments of cash in short−term money market instruments.

ReceivablesIn evaluating the realizability of its accounts receivable, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based uponpayment history and the customer’s current creditworthiness, as determined by the Company’s review of its customers’ credit information. The Company extendscredit on an unsecured basis to many of its customers. At December 31, 2003 and 2004 and September 30, 2005, the Company recorded no allowance foruncollectible accounts receivable impairment.

Property, Plant and EquipmentProperty and Equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Depreciation expense is recorded for eachasset over its estimated useful life using the straight−line method.

Impairment of Long−Lived AssetsThe Company reviews its long−lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not berecoverable. If it is determined that an asset’s estimated undiscounted future cash flows will not be sufficient to recover its carrying amount, an impairmentcharge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.

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Fair Value of Financial Instruments

For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair values because of the short maturity of these instruments. Thecarrying value of long−term debt approximates fair market value since interest rates approximate current market rates.

Derivative InstrumentsThe Company applies the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities”(“SFAS No. 133”). SFAS No. 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value.Changes in a derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met.

Intangible AssetsAt September 30, 2005, the Company had $12.4 million of intangible assets, net of accumulated amortization of $0.5 million, which was recorded in connectionwith natural gas gathering contracts assumed in consummated acquisitions (see Note 7). There were no intangible assets recorded as of December 31, 2003 or2004. Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) requires that intangible assets with finiteuseful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known,that intangible asset must be amortized over the best estimate of its useful life. At a minimum, the Company will assess the useful lives and residual values of allintangible assets on an annual basis to determine if adjustments are required. Amortization expense on the natural gas gathering contract intangible assets, whichhave an estimated life of 12 years and are being amortized on a straight−line basis, was $0.5 million for the nine months ended September 30, 2005. There wasno amortization expense on intangible assets recorded during the three years ended December 31, 2004 and the nine months ended September 30, 2004.Amortization expense related to intangible assets is estimated to be $1.1 million for each of the next five calendar years commencing 2006.

GoodwillAt December 31, 2003 and 2004 and September 30, 2005, the Company had $2.3 million, $2.3 million and $80.2 million, respectively, of goodwill which wasrecognized in connection with consummated acquisitions (see Note 7). The Company tests its goodwill for impairment at each year end by comparing fair valuesto its carrying values. The evaluation of impairment under SFAS No. 142 requires the use of projections, estimates and assumptions as to the future performanceof the Company’s operations, including anticipated future revenue, expected future operating costs and the discount factor used. Actual results could differ fromprojections, resulting in revisions to the Company’s assumptions and, if required, recognition of an impairment loss. The Company’s test of goodwill atDecember 31, 2004 resulted in no impairment, and no impairment indicators have been noted as of September 30, 2005. The Company will continue to evaluateits goodwill at least annually and if impairment indicators arise, will reflect the impairment of goodwill, if any, within the consolidated statements of income inthe period in which the impairment is indicated.

Federal Income TaxesThe Company is a limited liability corporation and Atlas Pipeline is a limited partnership. As a result, the Company’s and Atlas Pipeline’s income for federalincome tax purposes is reportable on the tax

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returns of the individual owners and partners, respectively. Accordingly, no recognition has been given to income taxes in the Company’s consolidated financialstatements.

Stock Based Compensation

The Company issues phantom units of the Partnership to its directors and employees of Atlas America and its affiliates under its Long−Term Incentive Plan (“thePlan”) (see Note 11). The Company accounts for the phantom units issued in connection with the Plan under Accounting Principles Board Opinion No. 25,“Accounting for Stock Issued to Employees” and its related interpretations.

Minority Interests in Atlas PipelineThe minority interests in our consolidated financial statements reflect the outside ownership interests in Atlas Pipeline, which were 61%, 76% and 84% atDecember 31, 2003 and 2004 and September 30, 2005, respectively. The minority interest in the Company’s consolidated net income is calculated quarterly bymultiplying (i) the weighted average Atlas Pipeline limited partner units outstanding held by non−affiliated third−parties by (ii) the consolidated net income perAtlas Pipeline limited partner unit for the respective quarter. The net income per Atlas Pipeline limited partner unit is calculated by dividing the net incomeallocated to limited partners, after the allocation of net income to the Company as general partner in accordance with the terms of the Atlas Pipeline partnershipagreement, by the total weighted average Atlas Pipeline limited partner units outstanding. The minority interest liability on the Company’s consolidated balancesheets principally reflects the sum of the allocation of Atlas Pipeline consolidated net income to the minority interests and the contributed capital of minorityinterests through the sale of limited partner units in Atlas Pipeline, partially offset by Atlas Pipeline quarterly cash distributions to the minority interest owners.

Environmental MattersThe Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has establishedprocedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Company accounts for environmental contingencies in accordance with Statement of Financial Accounting Standards No. 5, “Accounting forContingencies.” Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existingcondition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmentalassessments and/or clean−ups are probable, and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in partcertain environmental expenditures. At December 31, 2003 and 2004 and September 30, 2005, the Company had no environmental matters requiring specificdisclosure or requiring the recognition of a liability.

Segment InformationThe Company has two business segments: natural gas gathering and transmission located in the Appalachian Basin area (“Appalachia”) and gathering,transmission and processing located in the Mid−Continent area (“Mid−Continent”). Appalachian revenue is, for the most part, based on contractual arrangementswith Atlas America and its affiliates. Mid−Continent revenue is, for the most part, derived from the sale of residue gas and NGLs to purchasers at the tailgate ofthe processing plant.

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Revenue Recognition

Revenue in the Appalachian segment is recognized at the time the natural gas is transported through the gathering systems. Under the terms of its natural gasgathering agreements with Atlas America and its affiliates, the Company receives fees for gathering natural gas from wells owned by Atlas America, by drillinginvestment partnerships sponsored by Atlas America or by independent third parties. The fees received for the gathering services are generally the greater of 16%of the gross sales price for gas produced from the wells, or $0.35 or $0.40 per thousand cubic feet (“mcf”), depending on the ownership of the well. Substantiallyall gas gathering revenue is derived under this agreement. Fees for transportation services provided to independent third parties whose wells are connected to theCompany’s Appalachian gathering systems are at separately negotiated prices.

Revenue in the Mid−Continent segment is recognized at the time the natural gas is processed and the resulting residue gas and natural gas liquids (“NGLs”) aresold. The majority of this revenue is based on percentage of proceeds, or POP, and fixed−fee contracts. Under its POP purchasing arrangements, the Companypurchases natural gas at the wellhead, processes the natural gas by extracting NGLs and removing impurities and sells the residue gas and NGLs at market−basedprices, remitting to producers a contractually−determined percentage of the sale proceeds.

The Company accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, and oil and the receipt of a delivery statement. Thisrevenue is recorded based upon volumetric data from the Company’s records and management estimates of the related transportation and compression fees whichare, in turn, based upon applicable product prices (see Use of Estimates accounting policy for further description). The Company had unbilled revenue atDecember 31, 2003 and 2004 and September 30, 2005 of $2.6 million, $15.3 million and $42.1 million, respectively, included in accounts receivable andaccounts receivable−affiliates within the consolidated balance sheets.

Comprehensive Income (Loss)Comprehensive income (loss) includes net income and all other changes in the equity of a business during a period from transactions and other events andcircumstances from non−owner sources. These changes, other than net income, are referred to as “other comprehensive income (loss)” and for the Companyinclude only changes in the fair value of unsettled hedge contracts.

New Accounting StandardsIn May 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, “Accounting Changes and Error Corrections” (“SFAS No. 154”).SFAS No. 154 requires retrospective application to prior periods’ financial statements for changes in accounting principle. It also requires that the newaccounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicableand that a corresponding adjustment is made to the opening balance of retained earnings for that period rather than being reported in an income statement. Thestatement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS No.154 will depend on the nature and extent of any voluntary accounting changes and corrections of errors after the effective date, but management does notcurrently expect SFAS No. 154 to have a material impact on the Company’s financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which will result in (a)more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows

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associated with those obligations, and (c) more information about investments in long−lived assets because additional asset retirement costs will be recognized aspart of the carrying amounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in SFAS No. 143, “Accounting for AssetRetirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on afuture event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even thoughuncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirementobligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficientinformation to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending afterDecember 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation isencouraged. The Company does not expect FIN 47 to have a material impact on its consolidated financial statements.

In December 2004, the FASB issued SFAS No. 123 (R) (revised 2004) “Share−Based Payment,” which is a revision of SFAS No. 123, “Accounting forStock−Based Compensation.” SFAS No. 123 (R) supersedes Accounting Principals Board Opinion (“APB”) No. 25, “Accounting for Stock Issued toEmployees,” and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach to accounting in Statement 123 (R) requires all share−basedpayments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. Currently, theCompany follows APB No. 25 and its interpretations, which allow for valuation of share−based payments to employees at their intrinsic values. Under thismethodology, the Company recognizes compensation expense for phantom units granted at their fair value at the date of grant and compensation expense foroptions granted only if the current market price of the underlying units exceed the exercise price. SFAS No. 123 (R) is effective for the Company beginningJanuary 1, 2006. The Company does not expect SFAS No. 123 (R) to have a material impact on its consolidated financial statements.

NOTE 3 — ATLAS PIPELINE EQUITY OFFERINGSIn June 2005, Atlas Pipeline sold 2.3 million common units in a public offering for total gross proceeds of $96.5 million. The units were issued under AtlasPipeline’s previously filed Form S−3 shelf registration statement. The sale of the units resulted in net proceeds of approximately $91.7 million, after underwritingcommissions and other transaction costs. Atlas Pipeline primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its creditfacility.

In July 2004, Atlas Pipeline sold 2.1 million common units in a public offering for total gross proceeds of $73.0 million. The units were issued under AtlasPipeline’s previously filed Form S−3 shelf registration statement. The sale of the units resulted in net proceeds of approximately $67.5 million, after underwritingcommissions and other transaction costs. Atlas Pipeline utilized the net proceeds from the sale primarily to repay a portion of the amounts due under its creditfacility and to redeem preferred units issued in connection with the acquisition of Spectrum Field Services, Inc. in July 2004 for $20.4 million (see Note 7).

In April 2004, Atlas Pipeline sold 0.8 million common units in a public offering for total gross proceeds of $27.0 million. The units were issued under AtlasPipeline’s previously filed Form S−3 shelf registration statement. The sale of the units resulted in net proceeds of approximately $25.2 million, after underwritingcommissions and other transaction costs. Atlas Pipeline utilized the net proceeds from the sale primarily to repay a portion of the amounts due under its creditfacility.

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In May 2003, Atlas Pipeline sold 1.1 million common units in a public offering for total gross proceeds of $27.3 million. The units were issued under AtlasPipeline’s previously filed Form S−3 shelf registration statement. The sale of the units resulted in net proceeds of approximately $25.2 million, after underwritingcommissions and other transaction costs. Atlas Pipeline utilized the net proceeds from the sale primarily to repay a portion of the amounts due under its creditfacility.

NOTE 4 — ATLAS PIPELINE DISTRIBUTIONSAtlas Pipeline is required to distribute, within 45 days of the end of each quarter, all of its available cash (as defined in its partnership agreement) for that quarter.If distributions in any quarter exceed specified per unit target levels, the Company, as general partner, receives between 15% and 50% of such distributions inexcess of the specified target levels. Distributions declared by Atlas Pipeline for the period from January 1, 2002 through September 30, 2005 were as follows:

Date Atlas Pipeline Total AtlasAtlas Pipeline Cash Distribution Pipeline Cash

Cash Distribution per Limited Distribution ToPaid For Quarter Ended Partner Unit Limited Partners

(in thousands)May 10, 2002 March 31, 2002 $ 0.520 $ 843August 8, 2002 June 30, 2002 $ 0.535 $ 867November 8, 2002 September 30, 2002 $ 0.540 $ 875February 7, 2003 December 31, 2002 $ 0.540 $ 875

May 9, 2003 March 31, 2003 $ 0.560 $ 908August 8, 2003 June 30, 2003 $ 0.580 $ 1,574November 7, 2003 September 30, 2003 $ 0.620 $ 1,682February 6, 2004 December 31, 2003 $ 0.625 $ 1,696

May 7, 2004 March 31, 2004 $ 0.630 $ 1,710August 6, 2004 June 30, 2004 $ 0.630 $ 2,182November 5, 2004 September 30, 2004 $ 0.690 $ 3,839February 11, 2005 December 31, 2004 $ 0.720 $ 4,006

May 13, 2005 March 31, 2005 $ 0.750 $ 4,173August 5, 2005 June 30, 2005 $ 0.770 $ 6,055November 14, 2005 September 30, 2005 $ 0.810 $ 6,382

NOTE 5 — PROPERTY, PLANT AND EQUIPMENT

The following is a summary of property, plant and equipment (in thousands):

EstimatedDecember31,

September30, Useful Lives2003 2004 2005 in Years

Pipelines, processing and compression facilities $ 36,390 $ 168,932 $ 304,795 15 – 40Rights of way 623 14,128 15,109 20 – 40Buildings — 3,215 3,351 40Furniture and equipment — 517 700 3 – 7Other 5 307 562 3 – 10

37,018 187,099 324,517Less – accumulated depreciation (7,390) (11,840) (19,813)

$ 29,628 $ 175,259 $ 304,704

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In April 2005, Atlas Pipeline completed the acquisition of ETC Oklahoma Pipeline, Ltd. for approximately $196.0 million (see Note 7). Due to its recent date ofacquisition, the purchase price allocation is based upon estimated values determined by Atlas Pipeline, which are subject to adjustment and could changesignificantly as this preliminary allocation is further evaluated. At September 30, 2005, the portion of the purchase price allocated to property, plant andequipment for this acquisition by Atlas Pipeline (see Note 7) was included in pipelines, processing and compression facilities.

NOTE 6 — OTHER ASSETSThe following is a summary of other assets (in thousands):

December31,

September30,2003 2004 2005

Deferred finance costs, net of accumulated amortization of $106, $506 and $1,237 at December 31, 2003 and2004 and September 30, 2005, respectively $ 767 $ 3,316 $ 4,771Security deposits — 1,356 1,659Alaska Pipeline Company acquisition costs (see Note 13) 1,579 — —Other 76 — 425

$ 2,422 $ 4,672 $ 6,855

Deferred finance costs are recorded at cost and amortized over the term of the respective debt agreements (see Note 9).

NOTE 7 — ACQUISITIONS

SpectrumIn July 2004, Atlas Pipeline acquired Spectrum Field Services, Inc. (“Spectrum”), for approximately $141.6 million, including transaction costs and the paymentof taxes due as a result of the transaction. Spectrum’s principal assets included 1,900 miles of natural gas pipelines and a natural gas processing facility in Velma,Oklahoma. The acquisition was accounted for using the purchase method of accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”). Thefollowing table presents the purchase price allocation, including professional fees and other related acquisition costs, to the assets acquired and liabilitiesassumed, based on their fair values at the date of acquisition (in thousands):

Cash and cash equivalents $ 803Accounts receivable 18,505Prepaid expenses 649Property, plant and equipment 139,464Other long−term assets 1,054

Total assets acquired 160,475

Accounts payable and accrued liabilities (17,153)Hedging liabilities (1,519)Long−term debt (164)

Total liabilities assumed (18,836)

Net assets acquired $ 141,639

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The results of Spectrum’s operations are included within the Company’s consolidated financial statements from its date of acquisition. In connection withfinancing the acquisition of Spectrum, Atlas Pipeline issued preferred units to Resource America, Inc., an affiliate of Atlas America at the date of the transaction,and to Atlas America for an aggregate amount of $20.0 million. These preferred units were subsequently redeemed for $20.4 million, including a $0.4 millionpremium, with the net proceeds from Atlas Pipeline’s July 2004 equity offering (see Note 3).

Elk City

In April 2005, Atlas Pipeline acquired all of the outstanding equity interests in ETC Oklahoma Pipeline, Ltd. (“Elk City”), a Texas limited partnership, for$196.0 million, including related transaction costs. Elk City’s principal assets included 318 miles of natural gas pipelines located in the Anadarko Basin inwestern Oklahoma, a natural gas processing facility in Elk City, Oklahoma and a gas treatment facility in Prentiss, Oklahoma. The acquisition was accounted forusing the purchase method of accounting under SFAS No. 141. The following table presents the preliminary purchase price allocation, including professionalfees and other related acquisition costs, to the assets acquired and liabilities assumed, based on their fair values at the date of acquisition (in thousands)(unaudited):

Accounts receivable $ 5,587Other assets 497Property, plant and equipment 104,091Intangible assets 12,890Goodwill 77,896

Total assets acquired 200,961

Accounts payable and accrued liabilities (4,970)

Net assets acquired $ 195,991

Atlas Pipeline recorded goodwill in connection with this acquisition as a result of Elk City’s significant cash flow and its strategic industry position. The resultsof Elk City’s operations are included within the Company’s consolidated financial statements from its date of acquisition.

The following data presents unaudited pro forma revenue and net income for the Company as if the acquisitions discussed above and the equity offerings in April2004, July 2004 and June 2005, the net proceeds of which were principally utilized to repay debt borrowed to finance the acquisitions (see Note 3), had occurredon January 1, 2003. The Company has prepared these pro forma financial results for comparative purposes only. These pro forma financial results may not beindicative of the results that would have occurred if Atlas Pipeline had completed these acquisitions at the beginning of the periods shown below or the resultsthat will be attained in the future (in thousands):

Years Ended Nine Months EndedDecember31, September30,

2003 2004 2004 2005

Total revenue and other income $ 230,082 $ 294,285 $ 194,186 $ 275,853Net income $ 2,409 $ 6,714 $ 3,404 $ 7,306

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NOTE 8 — DERIVATIVE INSTRUMENTS

Atlas Pipeline enters into certain financial swap and option instruments that are classified as cash flow hedges in accordance with SFAS No. 133. Atlas Pipelineentered into these instruments to hedge the forecasted natural gas, NGL and condensate sales against the variability in expected future cash flows attributable tochanges in market prices. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying naturalgas, NGL and condensate is sold. Under these swap agreements, Atlas Pipeline receives a fixed price and pays a floating price based on certain indices for therelevant contract period.

Atlas Pipeline formally documents all relationships between hedging instruments and the items being hedged, including its risk management objective andstrategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. AtlasPipeline assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in offsetting changes in the forecasted cashflow of hedged items. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlationbetween the hedging instrument and the underlying commodity, Atlas Pipeline will discontinue hedge accounting for the derivative and subsequent changes inthe derivative fair value, which it determines through utilization of market data, will be recognized immediately within the Company’s consolidated statements ofincome.

Derivatives are recorded on the consolidated balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion ofchanges in fair value are recognized in owners’ equity as accumulated other comprehensive income (loss) and reclassified to natural gas and liquids revenuewithin the consolidated statements of income as the underlying transactions are settled. For non−qualifying derivatives and for the ineffective portion ofqualifying derivatives, changes in fair value are recognized within the consolidated statements of income as they occur. At December 31, 2004 andSeptember 30, 2005, the Company reflected net hedging liabilities on its consolidated balance sheets of $2.6 million and $46.7 million, respectively. Prior to theacquisition of Spectrum in July 2004, Atlas Pipeline had not entered into derivative instruments. Of the $46.4 million net loss in accumulated othercomprehensive income (loss) at September 30, 2005, if the fair values of the instruments remain at current market values, $22.7 million of losses will bereclassified to the consolidated statements of income over the next twelve month period as these contracts expire and $23.7 million will be reclassified in laterperiods. Actual amounts that will be reclassified will vary as a result of future price changes. Ineffective hedge gains or losses are recorded in natural gas andliquids revenue within the consolidated statements of income while the hedge contract is open and may increase or decrease until settlement of the contract. TheCompany recognized losses of $2,000 for the year ended December 31, 2004 and $27,000 and $4.4 million for the nine months ended September 30, 2004 and2005, respectively, within its consolidated statements of income related to the settlement of qualifying hedge instruments. The Company also recognized lossesof $0.3 million for the year ended December 31, 2004 and $0.7 million for both the nine months ended September 30, 2004 and 2005 within its consolidatedstatements of income related to the change in market value of non−qualifying or ineffective hedges.

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As of December 31, 2004, the Company had the following natural gas liquids, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Fixed — Price Swaps

Twelve Average Fair ValueMonths Volumes Fixed Price Liability(1)

Ended December31, (gallons) (per gallon) (in thousands)

2005 12,564,000 $ 0.550 $ (1,208)2006 6,804,000 0.575 (500)

$ (1,708)



Ended December31, (MMBTU)(2) (per MMBTU) (in thousands)

2005 970,000 $ 6.187 $ (71)2006 450,000 5.920 (172)

$ (243)

Crude Oil Fixed — Price Swaps


Ended December31, (barrels) (per barrel) (in thousands)

2006 18,000 $ 38.767 $ (36)

Crude Oil Options

Twelve Average Fair ValueMonths Option Type Volumes Strike Price Liability(3)

Ended December31,(barrels) (per barrel)

(inthousands)

2005 Puts purchased 75,000 $ 30.00 $ —2005 Calls sold 75,000 34.30 (640)

$ (640)

Total liability $ (2,627)



(2) MMBTU represents Million British Thermal Units.


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As of September 30, 2005, the Company had the following NGLs, natural gas, and crude oil volumes hedged:

Natural Gas Liquids Fixed – Price Swaps


Ended September30, (gallons) (per gallon) (in thousands)

2006 38,586,000 $ 0.673 $ (16,742)2007 38,115,000 0.711 (12,188)2008 34,587,000 0.702 (9,037)2009 7,434,000 0.697 (1,781)

$ (39,748)



Ended September30, (MMBTU)(2 ) (per MMBTU) (in thousands)

2006 3,923,000 $ 7.169 $ (5,767)2007 1,560,000 7.210 (1,658)2008 510,000 7.262 (1,037)

$ (8,462)

Natural Gas Basis Swaps

Twelve Average Fair ValueMonths Volumes Fixed Price Asset(3)

Ended September30, (MMBTU)(2) (per MMBTU) (in thousands)

2006 4,262,000 $ (0.517) $ 1,3762007 1,560,000 (0.522) 1,5842008 510,000 (0.544) 1,383

$ 4,343

Crude Oil Fixed – Price Swaps


Ended September30, (barrels) (per barrel) (in thousands)

2006 67,800 $ 51.329 $ (1,056)2007 80,400 55.187 (844)2008 82,500 58.475 (414)

$ (2,314)

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Crude Oil Options

Twelve Average Fair ValueMonths Volumes Strike Price Liability(3)

Ended September30,Option Type (barrels) (per barrel)

(inthousands)

2006 Putspurchased 15,000 $ 30.00 $ —

2006 Calls sold 15,000 34.25 (481)

$ (481)

Total netliability $ (46,662)


(2) MMBTU represents million British Thermal Units.


NOTE 9 — LONG−TERM DEBT

Total debt consists of the following (in thousands):

December31, September30,2004 2005

Atlas Pipeline Credit Facility:Revolving credit facility $ 10,000 $ 183,500Term loan 44,250 —Other debt 202 145

54,452 183,645Less current maturities (2,303) (63)

$ 52,149 $ 183,582

In April 2005, Atlas Pipeline entered into a new $270.0 million credit facility (the “Credit Facility”) with a syndicate of banks, which replaced its existing $135.0million facility. The facility was comprised of a five−year $225.0 million revolving line of credit and a five−year $45.0 million term loan. The term loan portionof the Credit Facility was repaid and retired from the net proceeds of the June 2005 equity offering (see Note 3). The revolving portion of the Credit Facilitybears interest, at Atlas Pipeline’s option, at either (i) Adjusted LIBOR plus the applicable margin, as defined, or (ii) the higher of the federal funds rate plus 0.5%or the Wachovia Bank prime rate (each plus the applicable margin). The weighted average interest rate on the outstanding Credit Facility borrowings atDecember 31, 2004 and September 30, 2005 was 7.0% and 6.6%, respectively. The interest rate on the outstanding balance of the term loan at December 31,2004 was 7.75%. Up to $10.0 million of the credit facility may be utilized for letters of credit, of which $2.2 million and $7.7 million was outstanding atDecember 31, 2004 and September 30, 2005, respectively. These outstanding letter of credit amounts were not reflected as borrowings on the Company’sconsolidated balance sheet. Borrowings under the Credit Facility are secured by a lien on and security interest in all of Atlas Pipeline’s property and that of itssubsidiaries, and by the guaranty of each of Atlas Pipeline’s subsidiaries.

The Credit Facility contains customary covenants, including restrictions on Atlas Pipeline’s ability to incur additional indebtedness; make certain acquisitions,loans or investments; make distribution payments to its unitholders if an event of default exists; or enter into a merger or sale of assets, including

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the sale or transfer of interests in its subsidiaries. The Credit Facility also contains covenants requiring Atlas to maintain, on a rolling four−quarter basis, amaximum total debt to EBITDA ratio (each as defined in the credit agreement) of 5.5 to 1, reducing to 4.5 to 1 on September 30, 2005 and thereafter; and aninterest coverage ratio (as defined in the credit agreement) of at least 3.0 to 1. Atlas Pipeline was in compliance with these covenants as of September 30, 2005,and was in compliance with the covenants of its previously existing credit facility as of December 31, 2004. Based upon the definitions set forth within the creditagreement, Atlas Pipeline’s ratio of total debt to EBITDA was 3.7 to 1 and the interest coverage ratio was 4.8 to 1 at September 30, 2005.

The aggregate amount of long−term debt maturities is as follows (in thousands):

Twelve Months Ended September 30:

2006 $ 632007 622008 202010 183,500

$ 183,645

Cash payments for interest related to long−term debt were $0.2 million, $0.2 million, and $2.1 million for the years ended December 31, 2002, 2003 and 2004,respectively.

NOTE 10 — COMMITMENTS AND CONTINGENCIES Atlas Pipeline has noncancelable operating leases for equipment and office space. Total rental expense for the years ended December 31, 2002, 2003 and2004 was $0.8 million, $1.0 million, and $0.8 million, respectively. The aggregate amount of remaining future minimum annual lease payments as ofSeptember 30, 2005 is as follows (in thousands):

Twelve Months Ended September 30:

2006 $ 1,3082007 1,4002008 6782009 2602010 143

$ 3,789

Atlas is a party to various routine legal proceedings arising out of the ordinary course of its business. Management of the Company believes that the ultimateresolution of these actions, individually or in the aggregate, will not have a material adverse effect on its financial condition or results of operations.

On March 9, 2004, the Oklahoma Tax Commission (“OTC”) filed a petition against Spectrum alleging that Spectrum underpaid gross production taxes beginningin June 2000. The OTC is seeking a settlement of $5.0 million plus interest and penalties. Atlas Pipeline plans on defending this action vigorously. In addition,under the terms of the Spectrum purchase agreement, $14.0 million has been placed in escrow to cover the costs of any adverse settlement resulting from thepetition and other indemnification obligations of the purchase agreement.

As of September 30, 2005, the Company is committed to expend approximately $36.6 million on pipeline extensions, compressor station upgrades andprocessing facility upgrades, including $13.1 million related to the Sweetwater Plant (see further description at “Subsequent Events”).

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NOTE 11 — LONG−TERM INCENTIVE PLAN

Atlas Pipeline has a Long−Term Incentive Plan that was established in February 2004 (“LTIP”) in which officers, employees and non−employee managing boardmembers of the Company and employees of the Company’s affiliates and consultants are eligible to participate. The LTIP is administered by a committee (the“Committee”) appointed by the Company’s managing board. The Committee may make awards of either phantom units or unit options for an aggregate of435,000 common units. Only phantom units have been granted under the LTIP through September 30, 2005.

A phantom unit entitles a grantee to receive a common unit upon vesting of the phantom unit or, at the discretion of the Committee, cash equivalent to the fairmarket value of a common unit. In addition, the Committee may grant a participant a distribution equivalent right (“DER”), which is the right to receive cash perphantom unit in an amount equal to, and at the same time as, the cash distributions Atlas Pipeline makes on a common unit during the period the phantom unit isoutstanding. A unit option entitles the grantee to purchase Atlas Pipeline’s common limited partner units at an exercise price determined by the Committee at itsdiscretion. The Committee also has discretion to determine how the exercise price may be paid by the participant. Except for phantom units awarded tonon−employee managing board members of the Company, the Committee will determine the vesting period for phantom units and the exercise period foroptions. Through September 30, 2005, phantom units granted under the LTIP generally had vesting periods of four years. The vesting period may also includethe attainment of predetermined performance targets, which could increase or decrease the actual award settlement, as determined by the Committee. Phantomunits awarded to non−employee managing board members will vest over a four year period. Awards will automatically vest upon a change of control, as definedin the LTIP. Of the units outstanding under the LTIP at September 30, 2005, 31,214 units will vest within the following twelve months.

The Company accounts for equity awards under the LTIP in accordance with the provisions of APB No. 25 and its interpretations, which allows for valuation ofthese awards at their intrinsic values. Under this methodology, the Company recognizes compensation expense for phantom units granted at their fair value at thedate of grant. For options granted, the Company recognizes compensation expense at the date of the grant only if the current market price of the underlying unitsexceeds the exercise price.

The following table sets forth the LTIP phantom unit activity for the periods indicated:


2002 2003 2004 2004 2005

Outstanding, beginning of period — — — — 58,752Granted(1) — — 59,598 59,598 67,338Performance factor adjusted(2) — — — — 82,468Matured — — — — (14,686)Forfeited — — (846) (846) (1,019)

Outstanding, end of period — — 58,752 58,752 192,853

Non−cash compensation expense recognized(in thousands) $ — $ — $ 700 $ 342 $ 2,809

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(1) The weighted average price for phantom unit awards on the date of grant was $37.14 for awards granted for the year ended December 31, 2004 and $37.14and $48.58 for awards granted for the nine months ended September 30, 2004 and 2005, respectively. There were no units awarded for the years endedDecember 31, 2002 and 2003.

(2) Consists of adjustments to performance−based awards to reflect actual performance.

NOTE 12 — RELATED PARTY TRANSACTIONS

The Company, which is wholly−owned by Atlas America, is affiliated with Resource America, Inc., a publicly−traded entity, and its subsidiaries (“RAI”). AtlasAmerica was a 100% owned subsidiary of RAI through the effective date of its initial public offering (May 2004) and an 80% owned subsidiary from that datethrough June 29, 2005. On June 30, 2005, Resource America distributed its 10.7 million shares of Atlas America to its shareholders. In connection with thisdistribution of Atlas America common stock to its shareholders, RAI and Atlas America entered into various agreements, including shared services and a taxmatters agreement, which govern the ongoing relationship between the two companies.

Atlas Pipeline is dependent upon the resources and services provided by RAI, Atlas America and their affiliates and subsidiaries. Accountsreceivable/payable−affiliates represents the net balance due from/to these related entities for natural gas transported through the gathering systems, net ofreimbursements for Atlas Pipeline costs and expenses paid by these Affiliates. Substantially all of Atlas Pipeline’s revenue in Appalachia is from these Affiliates.

Atlas Pipeline does not directly employ any persons to manage or operate its business. These functions are provided by the Company, as general partner, andemployees of these affiliated entities, primarily Atlas America. The Company does not receive a management fee or other compensation in connection with itsmanagement of Atlas Pipeline apart from its interest as general partner and its right to receive incentive distributions. Atlas Pipeline reimburses the Companyand/or its Affiliates for all direct and indirect costs of services provided, including the cost of employees, officer and managing board member compensation andbenefits properly allocable to Atlas Pipeline and all other expenses necessary or appropriate to the conduct of the business of, and allocable to, Atlas Pipeline.The partnership agreement provides that the Company, as general partner, will determine the costs and expenses that are allocable to Atlas Pipeline in anyreasonable manner it determines by the Company in its sole discretion.

Under an agreement with Atlas America and certain of its subsidiaries, Atlas America must construct up to 2,500 feet of sales lines from its existing wells to apoint of connection to Atlas Pipeline’s gathering systems. Atlas Pipeline must, at its own cost, extend its system to connect to any such lines extended to within1,000 feet of its gathering systems. With respect to wells to be drilled by Atlas America that will be more than 3,500 feet from Atlas Pipeline’s gatheringsystems, Atlas Pipeline has various options to connect those wells to its gathering systems at its own cost.

In connection with the proposed acquisition of Alaska Pipeline Company, L.L.C. (“Alaska Pipeline”) (see Note 13), Atlas Pipeline paid RAI a fee of $70,750 inthe year ended December 31, 2004.

NOTE 13 — SETTLEMENT OF ALASKA PIPELINE ARBITRATIONIn September 2003, Atlas Pipeline entered into an agreement with SEMCO Energy, Inc. (“SEMCO”) to purchase all of the stock of Alaska Pipeline. In order tocomplete the acquisition, Atlas Pipeline needed the approval of the Regulatory Commission of Alaska. The Regulatory Commission initially approved thetransaction, but on June 4, 2004, it vacated its order of approval based upon a motion for clarification or reconsideration filed by SEMCO. On July 1, 2004,SEMCO sent Atlas Pipeline a notice purporting to

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terminate the transaction. Atlas Pipeline pursued its remedies under the acquisition agreement. In connection with the acquisition, subsequent termination andlegal action, Atlas Pipeline incurred costs of approximately $4.0 million. On December 30, 2004, Atlas Pipeline entered into a settlement agreement withSEMCO settling all issues and matters related to SEMCO’s termination of the sale of Alaska Pipeline to Atlas Pipeline and SEMCO paid Atlas Pipeline $5.5million. Atlas Pipeline recognized expenses of $3.0 million and $0.1 million related to this terminated transaction for the nine month periods ended September30, 2004 and 2005, respectively, and a net gain of $1.5 million for the year ended December 31, 2004. These amounts are shown under the caption “(Gain) losson arbitration settlement, net” on the Company’s consolidated statements of income.

NOTE 14 – OPERATING SEGMENT INFORMATION

The Company has two business segments: natural gas gathering and transmission located in the Appalachian Basin area (“Appalachia”) of eastern Ohio, westernNew York and western Pennsylvania, and gathering and processing located in the Mid−Continent area (“Mid−Continent”) of southern Oklahoma and northernTexas. Appalachia revenue is principally based on contractual arrangements with Atlas and its affiliates. Mid−Continent revenue is primarily derived from thesale of residue gas and NGLs to purchasers at the tailgate of the processing plants. These operating segments reflect the way the Company manages itsoperations.

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The following tables summarize the Company’s operating segment data for the periods indicated (in thousands):


2002 2003 2004 2004 2005

Mid−Continent:RevenueNatural gas andliquids $ — $ — $ 72,109 $ 30,048 $ 218,268Interest income andother — — 60 24 77

Total revenue andother income — — 72,169 30,072 218,345

Costs and expensesNatural gas andliquids — — 58,707 24,588 184,578Plant operating — — 2,032 931 7,242General andadministrative — — 1,088 634 4,307Depreciation andamortization — — 2,408 613 6,597

Total costs andexpenses — — 64,235 26,766 202,724

Segment profit $ — $ — $ 7,934 $ 3,306 $ 15,621

Appalachia:RevenueTransportation andcompression –affiliates $ 10,581 $ 15,563 $ 18,724 $ 13,292 $ 16,447Transportation andcompression – thirdparties 79 88 76 52 54Interest income andother 7 98 322 258 275

Total revenue andother income 10,667 15,749 19,122 13,602 16,776

Costs and expenseTransportation andcompression 2,062 2,421 2,260 1,709 2,169General andadministrative 741 831 1,777 1,133 2,410Depreciation andamortization 1,475 1,770 2,063 1,519 1,898

Total costs andexpenses 4,278 5,022 6,100 4,361 6,477

Segment profit $ 6,389 $ 10,727 $ 13,022 $ 9,241 $ 10,299

Reconciliation ofsegment profit to netincome:Segment profitMid−Continent $ — $ — $ 7,934 $ 3,306 $ 15,621Appalachia 6,389 10,727 13,022 9,241 10,299

Total segment profit 6,389 10,727 20,956 12,547 25,920General andadministrative (741) (831) (1,777) (1,134) (2,410)Interest (250) (258) (2,301) (1,202) (8,478)


Gain (loss) onarbitration settlement,net — — 1,457 (2,987) (138)Minority interest (2,496) (5,066) (10,941) (3,300) (7,240)

Net income $ 2,902 $ 4,572 $ 7,394 $ 3,924 $ 7,654

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December31,

September30,2003 2004 2005

Balance sheetTotal assets:Mid−Continent $ — $ 157,675 $ 426,628Appalachia 32,447 39,400 40,766Corporate other 30,723 37,823 17,064

$ 63,170 $ 234,898 $ 484,458

Goodwill:Mid−Continent $ — $ — $ 77,896Appalachia 2,305 2,305 2,305

$ 2,305 $ 2,305 $ 80,201

The following tables summarize the Company’s total revenue by product or service for the periods indicated (in thousands):


2002 2003 2004 2004 2005

Natural gas andliquids:Natural gas $ — $ — $ 38,908 $ 15,973 $ 122,837NGLs — — 31,631 14,031 86,761Condensate — — 589 (294) 3,768Other (1) — — 981 338 4,902

Total $ — $ — $ 72,109 $ 30,048 $ 218,268

TransportationandCompression:Affiliates $ 10,581 $ 15,563 $ 18,724 $ 13,292 $ 16,447Third parties 79 88 76 52 54

Total $ 10,660 $ 15,651 $ 18,800 $ 13,344 $ 16,501

(1) Includes treatment, processing, and other revenue associated with the products noted.

Atlas Pipeline sells natural gas and NGLs under contract to various purchasers in the normal course of business. For the year ended December 31, 2004, theMid−Continent segment had two customers that accounted for approximately 34% and 25% of the Company’s consolidated total revenue. Additionally, theMid−Continent segment had two customers that accounted for 39% and 31% of the Company’s consolidated accounts receivable at December 31, 2004.Substantially all of the Appalachian segment’s revenue is derived from a master gas gathering agreement with Atlas America.

NOTE 15 — SUBSEQUENT EVENTS (UNAUDITED)On January 9, 2006, Atlas Pipeline declared a cash distribution of $0.83 per unit on its limited partner units, representing the cash distribution for the quarterended December 31, 2005. The distribution will be paid on February 14, 2006 to unitholders of record at the close of business on February 7, 2006.

On December 20, 2005, Atlas Pipeline issued $250.0 million of 8.125% senior unsecured notes in a private placement for net proceeds of approximately $243.1million, after estimated underwriting

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commissions and other transaction costs. Atlas Pipeline utilized the net proceeds principally to repay indebtedness under its credit facility.

On November 28, 2005, Atlas Pipeline sold 2.7 million of its common units in a public offering for gross proceeds of $113.4 million. In addition, pursuant to anoption granted to the underwriters of the offering, Atlas Pipeline sold 0.3 million common units on December 27, 2005 for gross proceeds of $13.9 million, oraggregate total gross proceeds of $127.3 million including the November 2005 offering. The units were issued under the Atlas Pipeline’s previously filed FormS−3 shelf registration statement. The sale of the units resulted in net proceeds of approximately $120.9 million, after estimated underwriting commissions andother transaction costs. Atlas primarily utilized the net proceeds from the sale to repay a portion of the amounts due under its credit facility. Subsequent to thisequity offering, the Company’s ownership interest in Atlas Pipeline was 14.8%, including its 2.0% general partner interest.

On October 31, 2005, Atlas Pipeline acquired all of the outstanding equity interests in a subsidiary of OGE Energy Corp. which owns a 75% operating interest inNOARK Pipeline System, Limited Partnership (“NOARK”). NOARK’s assets include a FERC−regulated interstate pipeline and an unregulated natural gasgathering system. Total consideration of $173.2 million, including $10.2 million for working capital adjustments, was funded through borrowings under AtlasPipeline amended credit facility, which was temporarily increased to a borrowing capacity of $400 million.

On October 19, 2005, Atlas Pipeline announced plans to construct a new cryogenic gas processing plant in Beckham County, Oklahoma. The new facility, to beknown as the Sweetwater gas plant, will be located west of Atlas Pipeline Elk City gas plant, and is being built to further access natural gas production activelybeing developed in western Oklahoma and the Texas panhandle. Atlas Pipeline expects the Sweetwater plant to be completed in the third quarter of 2006.

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Report of Independent Auditors

The Board of Directors ofEnogex Arkansas Pipeline Corporation

We have audited the accompanying consolidated balance sheets of Enogex Arkansas Pipeline Corporation as of December 31, 2004 and 2003, and the relatedconsolidated statements of income, retained earnings (deficit), and cash flows for the years then ended. These financial statements are the responsibility of theCompany’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform theaudit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of theCompany’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing auditprocedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control overfinancial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosuresin the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Enogex Arkansas PipelineCorporation at December 31, 2004 and 2003, and the consolidated results of its operations and its cash flows for the years then ended in conformity withaccounting principles generally accepted in the United States.

/s/ Ernst & Young LLP

Oklahoma City, OklahomaOctober 31, 2005

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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED BALANCE SHEETS

December31,

2004 2003

ASSETSCURRENT ASSETSCash and cash equivalents $ 3,156,938 $ 14,596,140Accounts receivable 1,046,153 501,635Accounts receivable — affiliates 5,061,974 3,536,891Accounts receivable — affiliates for income taxes — 993,575Accounts receivable — Southwestern and affiliates 2,112,338 1,610,235Prepayments and other 124,201 65,082Pipeline imbalance 197,884 1,089,421

Total current assets 11,699,488 22,392,979

PROPERTY, PLANT AND EQUIPMENTIn service 144,940,741 144,729,626Construction work in progress 150,893 52,780Other 2,034,072 2,034,072

Total property, plant and equipment 147,125,706 146,816,478Less accumulated depreciation 18,798,507 15,725,853

Net property, plant and equipment 128,327,199 131,090,625

Minority interest in NOARK 3,799,917 6,350,495

Other assets and deferred charges 1,574,600 1,717,514

TOTAL ASSETS $ 145,401,204 $ 161,551,613

See accompanying notes.

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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED BALANCE SHEETS (Continued)

December31,

2004 2003

LIABILITIES AND STOCKHOLDER’S EQUITYCURRENT LIABILITIESAccounts payable $ 5,393,537 $ 3,978,296Accounts payable — affiliates for income taxes 240,340 —Accounts payable — affiliates 1,145,301 608,254Accrued taxes other than income 858,717 842,325Accrued interest 399,208 699,447Accrued other 20,136 62,030Long−term debt due within one year 800,000 1,065,147Non−recourse debt of joint venture 1,200,000 1,200,000Pipeline imbalance 483,009 243,193

Total current liabilities 10,540,248 8,698,692

LONG−TERM DEBTNotes payable — 7,950,108Long−term debt 26,000,000 26,800,000Non−recourse debt of joint venture 39,000,000 40,200,000

Total long−term debt 65,000,000 74,950,108

DEFERRED LIABILITIESDeferred income taxes 19,585,000 17,282,000

Total deferred credits and other liabilities 19,585,000 17,282,000

COMMITMENTS AND CONTINGENCIES (Note 6)STOCKHOLDER’S EQUITY

Common stock, $1 par value; 1,000 shares authorized, issued and outstanding 1,000 1,000Retained earnings (Deficit) 2,118,152 (1,310,565)Advances from parent 48,156,804 61,930,378

Total stockholder’s equity 50,275,956 60,620,813

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY $ 145,401,204 $ 161,551,613


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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED STATEMENTS OF INCOME


2004 2003

OPERATING REVENUEGas transportation services $21,482,829 $20,142,212Natural gas sales 56,015,639 51,889,474Other revenue 5,700 6,075

Total operating revenue 77,504,168 72,037,761

COST OF GOODS SOLD 55,018,930 54,785,414

GROSS MARGIN 22,485,238 17,252,347

OPERATING EXPENSESGeneral and administrative expenses 3,755,849 3,904,945Operation and maintenance 3,333,126 3,514,728Depreciation 3,248,719 3,294,553Taxes other than income 1,101,303 1,100,050

Total operating expenses 11,438,997 11,814,276

OPERATING INCOME 11,046,241 5,438,071

OTHER INCOME (EXPENSE)Gain on sale of assets 8,424 5,894,700Other income 3,530 14,247Minority interest (491,979) (590,500)

Net other income (expense) (480,025) 5,318,447

INTEREST INCOME (EXPENSE)Interest income 199,629 98,663Gain on retirement of debt 111,361 —Interest on long−term debt and amortization (4,998,590) (5,141,590)Interest on short−term debt and other interest charges (288,322) (556,945)

Net interest income (expense) (4,975,922) (5,599,872)

INCOME BEFORE TAXES 5,590,294 5,156,646INCOME TAX EXPENSE 2,161,577 2,004,503

NET INCOME $ 3,428,717 $ 3,152,143


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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED STATEMENTS OF RETAINED EARNINGS (DEFICIT)


2004 2003

BALANCE AT BEGINNING OF PERIOD $(1,310,565) $(4,462,708)ADD: Net income 3,428,717 3,152,143

BALANCE AT END OF PERIOD $ 2,118,152 $(1,310,565)


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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED STATEMENTS OF CASH FLOWS


2004 2003

CASH FLOWS FROM OPERATING ACTIVITIESNet income $ 3,428,717 $ 3,152,143

Adjustments to reconcile net income to net cash provided by operating activitiesMinority interest in NOARK net income 491,979 590,500Gain on sale of assets (8,424) (5,894,700)Net book value of retired assets 4,319 38,542Depreciation 3,248,719 3,294,553Amortization of debt and prepaid costs 142,914 212,400Deferred income taxes 2,303,000 2,452,000

Change in certain current assets and liabilitiesAccounts receivable (544,518) (82,717)Accounts receivable — affiliates (1,033,613) (893,762)Materials and supplies inventories — 50,000Pipeline imbalance assets 891,537 (248,449)Prepayments and other current assets (59,119) (46,416)Accounts payable 1,415,241 156,849Accounts payable — affiliates 777,387 608,254Other accrued liabilities (25,502) (451,252)Accrued interest (300,239) 276,405Pipeline imbalance liabilities 239,816 (423,349)Other assets — 115,413Other liabilities (20,945) 898,578

Net Cash Provided by Operating Activities 10,951,269 3,804,992

CASH FLOWS FROM INVESTING ACTIVITIESCapital expenditures (571,614) (539,503)Proceeds from sale of assets 111,372 9,808,562Repayment of advances from parent (24,000,000) (7,500,000)Increase in advances from parent 10,226,426 3,411,935

Net Cash (Used in) Provided by Investing Activities (14,233,816) 5,180,994

CASH FLOWS FROM FINANCING ACTIVITIESRetirement of long−term debt (10,215,255) (2,000,000)Contribution from (Distribution to) minority interest 2,058,600 (2,500,000)

Net Cash Used in Financing Activities (8,156,655) (4,500,000)

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (11,439,202) 4,485,986CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 14,596,140 10,110,154

CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 3,156,938 $ 14,596,140

Supplemental Disclosure of Cash Flow Information:Cash paid for interest $ 4,897,750 $ 5,040,750


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ENOGEX ARKANSAS PIPELINE CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Organization

Enogex Arkansas Pipeline Corporation (“Company”), a wholly owned subsidiary of Enogex Inc. (“Enogex”) which itself is a wholly owned subsidiary of OGEEnergy Corp., owns an interest in the NOARK Pipeline System, Limited Partnership (“NOARK”), an Arkansas limited partnership. The Company’s ownershipinterest in NOARK with respect to assets, liabilities (exclusive of long−term debt), equity, income and expense is 75 percent. Under the partnership agreementand the NOARK Private Placement Memorandum, the Company is only responsible for 40 percent of the long−term debt of NOARK. At December 31, 2004, thegeneral partners of NOARK consisted of the Company and Southwestern Energy Pipeline Company (Southwestern), a wholly owned subsidiary of SouthwesternEnergy Company (SWN). The Company has a 75 percent interest (74 percent general partner interest and 1 percent limited partner interest) and Southwesternhas a 25 percent interest in NOARK.

NOARK has four wholly owned subsidiaries consisting of Ozark Gas Transmission, L.L.C. (Ozark), NOARK Energy Services, L.L.C. (“NES”), Ozark GasGathering, L.L.C. (“OGG”), and NOARK Pipeline Finance, L.L.C. (“Finance”). The operations of NOARK and its subsidiaries are organized into three activitiesincluding natural gas gathering, natural gas transportation and natural gas marketing. The operations of the gas transportation segment are conducted by Ozark, aFederal Energy Regulatory Commission regulated interstate pipeline that extends from Southeast Oklahoma through Arkansas to southeast Missouri. The naturalgas gathering and marketing operations are conducted by OGG. NES had no significant operations during 2004 or 2003. Finance was created to hold and servicethe debt of the Partnership.

As more fully discussed in Note 5, a substantial portion of the activities of NOARK during 2004 and 2003 were conducted with its general partners and theiraffiliates.

Principles of ConsolidationThe consolidated financial statements of the Company include the accounts and operations of the Company, NOARK and its subsidiaries. All intercompanyaccounts and transactions have been eliminated in consolidation.

Use of EstimatesIn preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets andliabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expensesduring the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s consolidated financial statements.

Allowance for Uncollectible Accounts ReceivableThe allowance for uncollectible accounts receivable is calculated based on outstanding accounts receivable balances over 180 days old. In addition, otheroutstanding accounts receivable balances less than 180 days old are reserved on a case−by−case basis when the Company believes the required payment ofspecific amounts owed is unlikely to occur. There was no allowance for uncollectible accounts receivable at December 31, 2004 and 2003, respectively.

Credit risk is the risk of financial loss to the Company if customers fail to perform their contractual obligations. The Company maintains credit policies withregard to its customers that management believes

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minimize overall credit risk. These policies include the evaluation of a potential customer’s financial condition (including credit rating) and collateralrequirements under certain circumstances. The Company also monitors the financial condition of existing customers on an ongoing basis.

Property, Plant and Equipment

All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at costs which include contracted services, direct labor,materials and overheads used during construction. Replacements of units of property are capitalized as plant. For group assets, the replaced plant is removedfrom plant balances and charged to accumulated depreciation. For non−group assets, the replaced plant is removed from plant balances with the relatedaccumulated depreciation and the remaining balance is recorded as a loss in the Consolidated Statements of Operations as Other Expense. Repair and removalcosts are included in the Consolidated Statements of Operations as Other Operation and Maintenance Expense.

The Company’s property, plant and equipment are divided into the following major classes at December 31, 2004 and 2003, respectively.

Year ended December 31 2004 2003

Transportation assets $ 139,178,829 $ 138,876,483Gathering assets 7,946,877 7,939,995

Total property, plant and equipment $ 147,125,706 $ 146,816,478

DepreciationDepreciation and amortization of the Company’s assets are computed using the straight−line method using estimated useful lives of three to 50 years fortransportation, three to 30 years for gathering.

Revenue RecognitionThe Company recognizes revenue from natural gas gathering and transportation services as the services are provided. Revenue associated with physical gas salesare recognized upon physical delivery of the gas.

Pipeline ImbalancesPipeline imbalances occur when the actual amounts of natural gas delivered from or received by the NOARK pipeline systems differ from the amounts scheduledto be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or made up in−kind. The Company values allimbalances at average market prices estimated to be in effect at the time the imbalance will be settled.

Minority InterestIn consolidation, the equity interest of Southwestern in NOARK has been adjusted per the provisions of the NOARK partnership agreement, as amended (the“Agreement”) and is shown on the balance sheet of the Company as a minority interest asset. The liquidation provisions of the partnership agreement provide forthe Company to receive a disproportionate share of the value of NOARK equity upon liquidation of NOARK. The minority interest asset value as ofDecember 31, 2004 and 2003 is $3,799,917 and $6,350,495 respectively.

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According to the terms of the agreement, NOARK’s net income (loss) is split between partners in three steps. First, a special revenue allocation, as defined in theAgreement may be made to Southwestern. This special revenue allocation is effective through December 31, 2009, and is calculated annually from an agreedupon maximum base amount ranging from $1,045,300 for 2003 and decreasing annually to $672,900 in 2009. The base amount may be reduced based upon anagreed upon formula specified in the Agreement, not to be less than zero. There was not a special revenue allocation to Southwestern for 2004 or 2003 based onthe agreed upon formula. Second, interest and debt amortization costs are split 60% to Southwestern and 40% to the Company. Third, the remaining net income(loss) is split 25% to Southwestern and 75% to the Company. In accordance with the Agreement, Southwestern and the Company are each required to fund theirshare of any NOARK cash flow deficiencies to the extent that they are not funded by NOARK’s operations.

2. Asset SaleIn 2002, Ozark entered into an Agreement of Sale and Purchase with Centerpoint Energy Gas Transmission Co. to sell approximately 29 miles of transmissionlines of the Ozark pipeline located in Pittsburg and Latimer counties in Oklahoma for approximately $10 million. Ozark received FERC approval for the sale onJanuary 6, 2003. Ozark recognized approximately a $5.3 million gain in 2003 which is included in gain on sale of assets in the accompanying consolidatedstatement of income.

3. Income TaxesThe items comprising income tax expense are as follows:


Benefit for Current Income TaxesFederal $ (119,266) $ (397,800)State (22,157) (49,697)

Total Benefit for Current Income Taxes (141,423) (447,497)Provision for Deferred Income TaxesFederal 1,967,000 2,094,000State 336,000 358,000

Total Provision for Deferred Income Taxes 2,303,000 2,452,000

Total Income Tax Expense $2,161,577 $2,004,503

The following schedule reconciles the statutory federal tax rate to the effective income tax rate:


Statutory federal tax rate 35.0% 35.0%State income taxes, net of federal income tax benefit 3.7 3.9

Effective income tax rate as reported 38.7% 38.9%

The Company is a member of an affiliated group that files consolidated income tax returns. Income taxes are allocated to each company in the affiliated groupbased on its separate taxable income or loss. The Company follows the provisions of SFAS No. 109, “Accounting for Income Taxes”, which uses an asset andliability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between thefinancial statement and income tax bases of

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assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on the changes in the asset or liability from period toperiod.

The components of Accumulated Deferred Taxes at December 31, 2004 and 2003, respectively, are as follows:

2004 2003

Non−Current Accumulated Deferred Tax LiabilitiesProperty $ 19,585,000 $ 17,267,000Other — 15,000

Total non−current tax liabilities $ 19,585,000 $ 17,282,000

4. Long−Term DebtOn June 15, 1998, NOARK issued $80 million of long−term notes in a private placement offering (the Notes) through Finance. The Notes mature on June 1,2018, and require semi−annual principal payments of $1.0 million plus interest at a fixed rate of 7.15% with a final balloon payment of $40 million due atmaturity. Enogex has guaranteed 40% of the Notes plus any accrued interest while SWN has guaranteed 60% of the Notes plus any accrued interest. Inconnection with the issuance of the Notes, NOARK incurred debt issuance costs of approximately $2.2 million, which are being amortized on a basis that closelyapproximates the effective interest method. In connection with the issuance of the Notes, NOARK entered into a forward interest rate swap contract to hedgeexposure to changes in prevailing interest rates on the Notes described above. Due to changes in treasury note rates, NOARK paid $1,112,000 to settle theforward interest rate swap contract in 1998. The unamortized portion is included in other assets and deferred charges on the consolidated balance sheets and isbeing amortized to interest expense over the life of the Notes.

On July 15, 2004 the Company retired a note that had been issued to a former interest owner of NOARK in the amount of $7,839,000. This note would havematured on July 1, 2020; as a result of retiring this note early the Company recognized a gain of approximately $111,000.

Interest expense amounted to $4,885,833 and $5,028,833 in 2004 and 2003, respectively. Amortization of the deferred charges amounted to $112,757 in 2004and 2003, and is included in interest on long−term debt in the accompanying consolidated statements of income.

Future maturities of long−term debt are as follows:

2005 $ 2,000,0002006 2,000,0002007 2,000,0002008 2,000,0002009 2,000,0002010 and beyond 57,000,000

Total long−term debt $ 67,000,000

The estimated fair value of the Notes is approximately $77.5 million and $93.9 million at December 31, 2004 and 2003, respectively. The fair value of thesenotes is based on management’s estimate of current rates available for similar issues with similar maturities.

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5. Related Party TransactionsApproximately $13,194,000 and $13,058,000 of gas sales, net of gathering services and fuel during the years ended December 31, 2004 and 2003, respectively,were generated with transactions from Southwestern and its affiliates. The Company also recorded approximately $6,976,000 and $7,037,000 in transmissionrevenue for the years ended December 31, 2004 and 2003, respectively from Southwestern and its’ affiliates. These revenue from Southwestern and its affiliatesrepresent approximately 26 percent and 28 percent of the Company’s total operating revenue for the years ended December 31, 2004 and 2003, respectively.

Approximately $42,569,000 and $38,739,000 of the gas sales, net of gathering services and fuel during the years ended December 31, 2004 and 2003,respectively, were generated by transactions with Enogex and its affiliates. The Company also recorded $4,143,000 and $4,258,000 in transmission revenue fromEnogex and its affiliates. This revenue from Enogex and its affiliates represents approximately 60 percent of the Company’s total operating revenue for both theyears ended December 31, 2004 and 2003. At December 31, 2004 and 2003, approximately $5,062,000 and $3,537,000 of accounts receivable, respectively, wereoutstanding with Enogex and its affiliates and are included in accounts receivable – affiliates in the accompanying consolidated balance sheets. Also recorded inNovember 2004 was a favorable price adjustment in the amount of $2,507,000 for gas sales to an Enogex affiliate by NOARK from May 2002 throughSeptember 2004.

Enogex and its affiliates also perform administrative, accounting, engineering field operations, legal and financial services for the Company, as well as NOARK.In 2003, Enogex allocated overhead costs to the Company in accordance with a formula based on the pro−rata amounts of property, headcount and gross marginof each business segment. In 2004 Enogex began using a method which allocates overhead based on hours incurred in support of each business segment.Approximately $3,756,000 and $3,905,000 of these charges are included in general and administrative expenses in 2004 and 2003, respectively in theconsolidated statements of income. At December 31, 2004 and 2003, the entire balance of accounts payable – affiliates in the accompanying consolidated balancesheets is due to Enogex and its affiliates. During 2004 and 2003, natural gas purchases of approximately $259,000 and $48,000, respectively, were made from anaffiliate of Enogex.

The balance of advances from Parent was $48,156,804 and $61,930,378 at December 31, 2004 and 2003, respectively. The advances originally consisted ofassets contributed by Enogex to NOARK in 1998. During 2004 and 2003, the Company repaid $24,000,000 and $7,500,000 of these advances. The advances arenon−interest bearing. Current transactions include administrative costs paid by the Parent on behalf of the Company and other costs allocated from the Parent tothe Company, totaling $10,226,426 and $3,411,935 in 2004 and 2003, respectively.

6. Commitments and ContingenciesIn the normal course of business, lawsuits and claims arise against the Company and its subsidiaries. Management of the Company, after consultation with legalcounsel, does not anticipate that liabilities arising from currently pending or threatened lawsuits and claims would result in losses, which would materially affectthe consolidated financial position of the Company or the results of its operations.

7. Business SegmentsThe Company manages its operations on a consolidated basis. The Company has no operations that would quality as a separate operating segment underStatement of Financial Standards (SFAS) No. 131 “Disclosure About Segments of an Enterprise and Related Information.

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8. Subsequent events

On October 31, 2005, Enogex sold all of it’s ownership in EAPC to Atlas Pipeline Partner, L.P. pursuant to a stock purchase agreement dated September 21,2005. As a condition of the sale, Enogex will continue to perform certain administrative functions for a period of time as required by the Transition ServiceAgreement.

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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED BALANCE SHEETS

(unaudited)

September30, December31,2005 2004

ASSETSCURRENT ASSETSCash and cash equivalents $ 14,501,542 $ 3,156,938Accounts receivable 784,716 1,046,153Accounts receivable — affiliates 5,145,094 5,061,974Accounts receivable — Southwestern and affiliates 2,090,862 2,112,338Prepayments and other 133,536 124,201Pipeline imbalance 191,258 197,884

Total current assets 22,847,008 11,699,488

PROPERTY, PLANT AND EQUIPMENTIn service 144,415,825 144,940,741Construction work in progress 58,742 150,893Other 2,034,072 2,034,072

Total property, plant and equipment 146,508,639 147,125,706Less accumulated depreciation 20,592,819 18,798,507

Net property, plant and equipment 125,915,820 128,327,199

Minority interest in NOARK 3,359,515 3,799,917Other assets and deferred charges 1,531,702 1,574,600

TOTAL ASSETS $ 153,654,045 $ 145,401,204


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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED BALANCE SHEETS (Continued)

(unaudited)

September30, December31,2005 2004

LIABILITIES AND STOCKHOLDER’S EQUITYCURRENT LIABILITIESAccounts payable $ 6,467,924 $ 5,393,537Accounts payable — affiliates 1,040,658 1,145,301Accounts payable — affiliates for income taxes 509,687 240,340Accrued taxes other than income 756,945 858,717Accrued interest 1,573,000 399,208Customer deposits 65,000 —Accrued other — 20,136Long−term debt due within one year 800,000 800,000Non−recourse debt of joint venture 1,200,000 1,200,000Pipeline imbalance 643,067 483,009

Total current liabilities 13,056,281 10,540,248

LONG−TERM DEBTLong−term debt 25,600,000 26,000,000Non−recourse debt of joint venture 38,400,000 39,000,000

Total long−term debt 64,000,000 65,000,000

DEFERRED LIABILITIESDeferred income taxes 21,893,000 19,585,000

Total deferred credits and other liabilities 21,893,000 19,585,000

COMMITMENTS AND CONTINGENCIES (Note 4)STOCKHOLDER’S EQUITY

Common stock, $1 par value; 1,000 shares authorized, issued and outstanding Common stock authorized, issuedand outstanding 1,000 1,000

Retained earnings 4,992,191 2,118,152Advances from parent 49,711,573 48,156,804

Total stockholder’s equity 54,704,764 50,275,956

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY $ 153,654,045 $ 145,401,204


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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED STATEMENTS OF INCOME

(unaudited)

Nine Months EndedSeptember30,

2005 2004

OPERATING REVENUEGas transportation services $15,128,825 $15,556,731Natural gas sales 42,362,507 37,677,107Other revenue 3,775 4,275

Total operating revenue 57,495,107 53,238,113

COST OF GOODS SOLD 40,551,222 40,327,285

GROSS MARGIN 16,943,885 12,910,828OPERATING EXPENSESGeneral and administrative expenses 2,206,424 2,613,129Operation and maintenance 2,699,306 2,371,186Depreciation 2,474,995 2,404,143Taxes other than income 848,187 809,722

Total operating expenses 8,228,912 8,198,180

OPERATING INCOME 8,714,973 4,712,648

OTHER INCOME (EXPENSE)Other income (expense) (54,586) 8,549Minority interest (440,402) 609,670

Net other income (expense) (494,988) 618,219

INTEREST INCOME (EXPENSE)Interest income 194,920 121,041Gain on retirement of debt — 111,361Interest on long−term debt and amortization (3,653,610) (3,760,860)Interest on short−term debt and other interest charges — (288,322)

Net interest expense (3,458,690) (3,816,780)

INCOME BEFORE TAXES 4,761,295 1,514,087INCOME TAX EXPENSE 1,887,257 584,577

NET INCOME $ 2,874,038 $ 929,510

See accompanying notes

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ENOGEX ARKANSAS PIPELINE CORPORATIONCONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

Nine Months EndedSeptember30,

2005 2004

CASH FLOWS FROM OPERATING ACTIVITIESNet income $ 2,874,038 $ 929,510Adjustments to reconcile net income to net cash provided byoperating activities

Minority interest in NOARK net income (loss) 440,402 (609,670)Gain on sale of assets — (8,424)Net book value of retired assets 60,493 —Depreciation 2,474,995 2,404,143Amortization 133,286 96,293Deferred income taxes 2,308,000 2,132,000

Change in certain current assets and liabilitiesAccounts receivable 261,437 (113,766)Accounts receivable — affiliates (61,644) (916,436)Pipeline imbalance assets 6,626 868,306Prepayments and other current assets (9,335) (22,173)Accounts payable 1,074,387 (13,889)Accounts payable — affiliates 164,704 325,101Other accrued liabilities (56,908) (126,480)Accrued interest 1,173,792 921,220Pipeline imbalance liabilities 160,058 417,576Other assets (88,338) —Other liabilities — (20,944)

Net Cash Provided by Operating Activities 10,915,993 6,262,367

CASH FLOWS FROM INVESTING ACTIVITIESCapital expenditures (126,158) (360,746)Proceeds from sale of assets — 111,372Increase in advances from parent 1,554,769 10,373,164

Net Cash Provided by Investing Activities 1,428,611 10,123,790

CASH FLOWS FROM FINANCING ACTIVITIESRetirement of long—term debt (1,000,000) (9,215,255)

Net Cash Used in Financing Activities (1,000,000) (9,215,255)

NET INCREASE IN CASH AND CASH EQUIVALENTS 11,344,604 7,170,902CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 3,156,938 14,596,140

CASH AND CASH EQUIVALENTS AT END OF PERIOD $14,501,542 $21,767,042

Supplemental Disclosure of Cash Flow Information:Cash paid for interest $ 2,395,250 $ 2,466,750


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ENOGEX ARKANSAS PIPELINE CORPORATIONNOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Organization

Enogex Arkansas Pipeline Corporation (“Company”), a wholly owned subsidiary of Enogex Inc. (“Enogex”) which is a wholly owned subsidiary of OGE EnergyCorporation, owns an interest in the NOARK Pipeline System, Limited Partnership (“NOARK”), an Arkansas limited partnership. The Company’s ownershipinterest in NOARK with respect to assets, liabilities (exclusive of long−term debt), equity, income and expense is 75 percent. Under the partnership agreementand the NOARK Private Placement Memorandum, the Company is only responsible for 40 percent of the long−term debt of NOARK. At September 30, 2005,the general partners of NOARK consisted of the Company and Southwestern Energy Pipeline Company (Southwestern), a wholly owned subsidiary ofSouthwestern Energy Company (SWN). The Company has a 75 percent interest (74 percent general partner interest and 1 percent limited partner interest) andSouthwestern has a 25 percent interest in NOARK.

NOARK has four wholly owned subsidiaries consisting of Ozark Gas Transmission, L.L.C. (Ozark), NOARK Energy Services, L.L.C. (“NES”), Ozark GasGathering, L.L.C. (“OGG”), and NOARK Pipeline Finance, L.L.C. (“Finance”). The operations of NOARK and its subsidiaries are organized into two activitiesincluding natural gas gathering and natural gas transportation. The operations of the gas transportation segment are conducted by Ozark, a Federal EnergyRegulatory Commission regulated interstate pipeline that extends from Southeast Oklahoma through Arkansas to southeast Missouri. The natural gas gatheringand marketing operations are conducted by OGG. NES had no operations during 2005 or 2004. Finance was created to hold and service the debt of thePartnership.

As more fully discussed in Note 3, a substantial portion of the activities of NOARK during 2005 and 2004 were conducted with its general partners and theiraffiliates.

Principles of ConsolidationThe consolidated financial statements of the Company include the accounts and operations of the Company, NOARK and its subsidiaries. All inter−companyaccounts and transactions have been eliminated in consolidation.

Basis of PresentationThe consolidated financial statements included herein have been prepared by the Company, without audit. In the opinion of management, all adjustmentsnecessary to fairly present the consolidated financial position of the Company at September 30, 2005 and December 31, 2004 and the results of its operations andcash flows for the nine months ended September 30, 2005 and 2004, have been included and are of a normal recurring nature. The consolidated financialstatements and Notes thereto should be read in conjunction with the audited consolidated financial statements and Notes thereto for the year ended December 31,2004.

Use of EstimatesIn preparing the consolidated financial statements, management is required to make estimates and assumptions that affect the reported amounts of assets andliabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expensesduring the reporting period. Changes to these assumptions and estimates could have a material effect on the Company’s consolidated financial statements.

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Allowance for Uncollectible Accounts Receivable

The allowance for uncollectible accounts receivable is calculated based on outstanding accounts receivable balances over 180 days old. In addition, otheroutstanding accounts receivable balances less than 180 days old are reserved on a case−by−case basis when the Company believes the required payment ofspecific amounts owed is unlikely to occur. There was no allowance for uncollectible accounts receivable at September 30, 2005 and December 31, 2004.

Credit risk is the risk of financial loss to the Company if customers fail to perform their contractual obligations. The Company maintains credit policies withregard to its customers that management believes minimize overall credit risk. These policies include the evaluation of a potential customer’s financial condition(including credit rating) and collateral requirements under certain circumstances. The Company also monitors the financial condition of existing customers on anongoing basis.

Property, Plant and EquipmentAll property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at costs which include contracted services, direct labor,materials and overheads used during construction. Replacements of units of property are capitalized as plant. For group assets, the replaced plant is removedfrom plant balances and charged to accumulated depreciation. For non−group assets, the replaced plant is removed from plant balances with the relatedaccumulated depreciation and the remaining balance is recorded as a loss in the Consolidated Statements of Operations as Other Expense. Repair and removalcosts are included in the Consolidated Statements of Operations as Other Operation and Maintenance Expense.

The Company’s property, plant and equipment are divided into the following major classes at September 30, 2005 and December 31, 2004.

2005 2004

Transportation assets $ 130,580,066 $ 139,178,829Gathering assets 15,928,573 7,946,877

Total property, plant and equipment $ 146,508,639 $ 147,125,706

DepreciationDepreciation and amortization of the Company’s assets are computed using the straight−line method using estimated useful lives of three to 50 years fortransportation, three to 30 years for gathering.

Revenue RecognitionThe Company recognizes revenue from natural gas gathering and transportation services as the services are provided. Revenue associated with physical gas salesare recognized upon physical delivery of the gas.

Pipeline ImbalancesPipeline imbalances occur when the actual amounts of natural gas delivered from or received by the NOARK pipeline systems differ from the amounts scheduledto be delivered or received. Imbalances are due to or due from shippers and operators and can be settled in cash or made up in−kind.

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Minority Interest

In consolidation, the equity interest of Southwestern in NOARK has been adjusted per the provisions of the NOARK partnership agreement, as amended (the“agreement”) and is shown on the balance sheet of the Company as a minority interest asset. The liquidation provisions of the partnership agreement provide forthe Company to receive a disproportionate share of the value of NOARK equity upon liquidation of NOARK. The minority interest asset value as ofSeptember 30, 2005 is $3,359,515 and at December 31, 2004 is $3,799,917.

According to the terms of the agreement, NOARK’s net income (loss) is split between partners in three steps. First, a special revenue allocation, as defined in theAgreement may be made to Southwestern. This special revenue allocation is effective through December 31, 2009, and is calculated annually from an agreedupon maximum base amount ranging from $979,100 for 2004 and decreasing annually to $672,900 in 2009. The base amount may be reduced based upon anagreed upon formula specified in the Agreement, not to be less than zero. There was not a special revenue allocation to Southwestern for the nine months endedSeptember 30, 2005 or 2004 based on the agreed upon formula. Second, interest and debt amortization costs are split 60% to Southwestern and 40% to theCompany. Third, the remaining net income (loss) is split 25% to Southwestern and 75% to the Company. In accordance with the Agreement, Southwestern andthe Company are each required to fund their share of any NOARK cash flow deficiencies to the extent that they are not funded by NOARK’s operations.

Income TaxesThe Company is a member of an affiliated group that files consolidated income tax returns. Income taxes are allocated to each company in the affiliated groupbased on its separate taxable income or loss. The Company follows the provisions of SFAS No. 109, “Accounting for Income Taxes”, which uses an asset andliability approach to accounting for income taxes. Under SFAS No. 109, deferred tax assets or liabilities are computed based on the difference between thefinancial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income tax expenses or benefits are based on thechanges in the asset or liability from period to period.

2. Long−Term DebtOn June 15, 1998, NOARK issued $80 million of long−term notes in a private placement offering (the Notes) through Finance. The Notes mature on June 1,2018, and require semi−annual principal payments of $1.0 million plus interest at a fixed rate of 7.15% with a final balloon payment of $40 million due atmaturity. Enogex has guaranteed 40% of the Notes plus any accrued interest while SWN has guaranteed 60% of the Notes plus any accrued interest. Inconnection with the issuance of the Notes, NOARK incurred debt issuance costs of approximately $2.2 million, which are being amortized on a basis that closelyapproximates the effective interest method. In connection with the issuance of the Notes, NOARK entered into a forward interest rate swap contract to hedgeexposure to changes in prevailing interest rates on the Notes described above. Due to changes in treasury note rates, NOARK paid $1,112,000 to settle theforward interest rate swap contract in 1998. The unamortized portion is included in other assets and deferred charges on the consolidated balance sheets and isbeing amortized to interest expense over the life of the Notes.

On July 15, 2004 the Company retired a note that had been issued to a former interest owner of NOARK in the amount of $7,839,000. This note would havematured on July 1, 2020; as a result of retiring this note early the Company recognized a gain of $111,000.

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Interest expense amounted to $3,569,042 and $3,676,292 in 2005 and 2004, respectively. Amortization of the deferred charges amounted to $84,568 in 2005 and2004, and is included in interest on long−term debt in the accompanying consolidated statements of income.

3. Related Party TransactionsApproximately $9,702,000 and $9,363,000 of gas sales, net of gathering services and fuel during the nine months ended September 30, 2005 and 2004,respectively, were generated by transactions with Southwestern and its affiliates. The Company also recorded approximately $4,956,000 and $5,306,000 intransmission revenue for the nine months ended September 30, 2005 and 2004, respectively, from Southwestern and its affiliates. This revenue representsapproximately 25 percent and 28 percent of the Company’s total operating revenue for the nine months ended September 30, 2005 and 2004, respectively.Approximately $32,423,000 and $28,130,000 of gas sales, net of gathering services and fuel during the nine months ended September 30, 2005 and 2004,respectively, were generated by transactions with Enogex and its affiliates. The Company also recorded approximately $1,999,000 and $3,219,000 intransmission revenue from Enogex and its affiliates. This revenue from Enogex and its affiliates represents approximately 61 percent and 59 percent of theCompany’s total operating revenue for the nine months ended September 30, 2005 and 2004, respectively. At September 30, 2005 and December 31, 2004,approximately $5,145,000 and $5,062,000 of accounts receivable, respectively, were outstanding with Enogex and its affiliates.

Enogex and its affiliates also perform administrative, accounting, engineering field operations, legal and financial services for the Company, as well as NOARK.Approximately $2,206,000 and $2,613,000 of these charges are included in general and administrative expenses in 2005 and 2004, respectively consolidatedstatements of income. At September 30, 2005 and December 31, 2004, the entire balance of accounts payable—affiliates in the accompanying consolidatedbalance sheets is due to Enogex and its affiliates.

During 2005 and 2004, natural gas purchases of approximately $182,000 and $169,000, respectively, were made from an affiliate of Enogex.

The balance of advances from Parent was $49,711,573 and $48,156,804 at September 30, 2005 and December 31, 2004, respectively. The advances originallyconsisted of assets contributed by Enogex to NOARK in 1998. Current transactions include administrative costs paid by the Parent on behalf of the Company andother costs allocated from the Parent to the Company. During the nine months ended September 30, 2005 and 2004, the Company did not repay any of theadvances from parent. In November 2004, the Company repaid $24,000,000 of these advances. The advances are non−interest bearing.

4. Commitments and ContingenciesIn the normal course of business, lawsuits and claims arise against the Company and its subsidiaries. Management of the Company, after consultation with legalcounsel, does not anticipate that liabilities arising from currently pending or threatened lawsuits and claims would result in losses, which would materially affectthe consolidated financial position of the Company or the results of its operations.

5. Subsequent EventsOn October 31, 2005, Enogex sold all of it’s ownership in EAPC to Atlas Pipeline Partner, L.P. pursuant to a stock purchase agreement dated September 21,2005. As a condition of the sale, Enogex will continue to perform certain administrative functions for a period of time as required by the Transition ServiceAgreement.

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Report of Independent Registered Public Accounting Firm

Board of Directors andAtlas Pipeline Partners, L.P.

We have audited the accompanying balance sheets of ETC Oklahoma Pipeline, Ltd. (a Texas limited partnership) as of August 31, 2004 and 2003, and the relatedstatements of income, partners’ capital, and cash flows for the year ended August 31, 2004 and the period from the beginning of operations (October 1, 2002)through August 31, 2003. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on thesefinancial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that weplan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is notrequired to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal controlover financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on theeffectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation. We believe that our audits provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of ETC Oklahoma Pipeline, Ltd. as ofAugust 31, 2004 and 2003, and the results of its operations and its cash flows for the year ended August 31, 2004 and the period from inception (September 24,2002) through August 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

/s/Grant Thornton LLPCleveland, OhioApril 25, 2005

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ETC OKLAHOMA PIPELINE, LTD.BALANCE SHEETS

August 31, 2004 and 2003(in thousands)

ASSETS 2004 2003

CURRENT ASSETS:Cash $ — $ —Receivables —

Trade 1,773 1,098Related parties 22,305 7,121Exchanges 213 730

Materials and supplies 63 63Other current assets — 49

Total current assets 24,354 9,061

PROPERTY, PLANT AND EQUIPMENT 47,492 40,305ACCUMULATED DEPRECIATION (3,938) (1,589)

PROPERTY, PLANT AND EQUIPMENT, NET 43,554 38,716

Total assets $67,908 $47,777

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:Payables —

Trade exchanges $19,825 $ 7,694Exchanges 188 576

Accrued expenses 577 640

Total current liabilities 20,590 8,910

COMMITMENTS AND CONTINGENCIES (See Note H)

PARTNERS’ CAPITALLimited partner 47,271 38,828General partner 47 39

Total partners’ capital 47,318 38,867

Total liabilities and partners’ capital $67,908 $47,777

The accompanying notes are an integral part of these financial statements.

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ETC OKLAHOMA PIPELINE, LTD.INCOME STATEMENTS

(in thousands)

Year EndedAugust 31, 2004

ElevenMonths EndedAugust 31, 2003

OPERATING REVENUE:Third party $ 11,977 $ 7,607Related party 123,320 84,834

Total revenue 135,297 92,441

COSTS AND EXPENSES:Cost of products sold 119,495 79,055Operating 4,726 2,914General and administrative 2,664 2,887Depreciation and amortization 2,249 1,591

Total costs and expenses 129,134 86,447

NET INCOME $ 6,163 $ 5,994


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ETC OKLAHOMA PIPELINE, LTD.STATEMENTS OF PARTNERS’ CAPITAL

August 31, 2004 and 2003(in thousands)

LimitedPartners’Capital

GeneralPartners’Capital

TotalPartners’Capital

Balance, October 1, 2002 $ — $ — $ —Capital contribution 32,840 33 32,873Net income 5,988 6 5,994

Balance, August 31, 2003 38,828 39 38,867Capital contribution 2,286 2 2,288Net income 6,157 6 6,163

Balance, August 31, 2004 $ 47,271 $ 47 $ 47,318


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ETC OKLAHOMA PIPELINE, LTD.STATEMENTS OF CASH FLOWS

(in thousands)


Eleven MonthsEnded

August 31, 2003

CASH FLOWS FROM OPERATING ACTIVITIES:Net income $ 6,163 $ 5,994Adjustments to reconcile net income to net cash provided by operating activities —

Depreciation and amortization 2,249 1,591Other, net 1 —Changes in operating assets and liabilities —

Receivables (157) (1,829)Related party receivables (7,181) (18,289)Other current assets 49 (49)Payables 11,743 8,269Accrued expenses (63) 380

Net cash provided by (used in) operating activities 12,804 (3,933)

CASH FLOWS FROM INVESTING ACTIVITIES:Additions to property, plant and equipment (4,873) (7,321)Proceeds from sale of assets 72 86

Net cash used in investing activities (4,801) (7,235)

CASH FLOWS FROM FINANCING ACTIVITIES:Working capital from (to) parent (8,003) 11,168

Net change in cash — —Cash beginning of year — —

Cash end of year $ — $ —

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:Non−cash asset contribution $ 2,288 $ 32,873

Cash paid for interest $ — $ —

Cash paid for income taxes $ — $ —


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ETC OKLAHOMA PIPELINE LTD.NOTES TO FINANCIAL STATEMENTS

A — ORGANIZATION AND BUSINESS

ETC Oklahoma Pipeline, Ltd. (Elk City or the Company) is a Texas limited partnership, which began operations in October 2002. LG PL, LLC, awholly−owned subsidiary of La Grange Acquisition, L.P. (La Grange) owns a 0.1% general partner interest and La Grange Acquisition, L.P. owns a 99.9%limited partner interest. Elk City owns a natural gas gathering pipeline system and gas processing plant in Oklahoma. La Grange acquired the Oklahomanatural gas gathering and gas processing assets of Aquila Gas Pipeline Corporation (Aquila), a subsidiary of Aquila, Inc., in October 2002. These assets arereferred to herein as “the Elk City system.”

The Elk City system is a 318−mile gathering system located in western Oklahoma that gathers, compresses, treats and processes natural gas from theAnadarko Basin. The Elk City system also includes the Elk City processing plant and one treating facility. The Elk City system is connected, either directlyor indirectly, to six major interstate and intrastate natural gas pipelines providing access to natural gas markets throughout the United States. The Elk Citysystem has a processing capacity of approximately 130 million cubic feet per day (MMcf/d).

B — SIGNIFICANT ACCOUNTING POLICIES

1. Basis of Presentation

Financial statements are presented for the year ended August 31, 2004 and for the eleven months ended August 31, 2003.

The financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America.

2. Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management tomake estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of thefinancial statements and the reported amounts of revenue and expenses during the reporting period.

Some of the other more significant estimates made by management include, but are not limited to the useful lives for depreciation and amortization andgeneral business reserves. Actual results could differ from those estimates.

3. Cash

La Grange provides cash to the Company for working capital and capital expenditures. Cash transfers are recorded through related party receivables andpayables. Cash receipts of the Company are immediately transferred to La Grange to reduce the intercompany balance with La Grange.

4. Accounts Receivable

Elk City deals with counter parties that are typically either investment grade (Standard & Poors BBB or higher) or are otherwise secured with a letter ofcredit or other form of security (corporate guaranty or prepayment). Management reviews accounts receivable balances each week. Credit limits areassigned and monitored for all counter parties. The majority of payments are due on the 25th of the month following delivery.

Management closely monitors credit exposure for potential doubtful accounts. Management believes that an occurrence of bad debt is unlikely; therefore, anallowance for doubtful accounts was not

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deemed necessary at August 31, 2004 and 2003, respectively. Bad debt expense is recognized at the time an account is deemed uncollectible. An accountreceivable will be written off in the event a counter party files for bankruptcy protection or the account is turned over for collection and the collector deemsthe account uncollectible. No bad debt expense was recorded during the year ended August 31, 2004 or the eleven months ended August 31, 2003.

5. Materials and Supplies

Materials and supplies are stated at the lower of cost (determined on a first−in, first−out basis) or market value.

6. Inventories and Exchanges

Inventories and exchanges consist of natural gas liquids (NGLs) on hand or natural gas and NGL delivery imbalances with others and are presented net bycustomer/supplier. These amounts turn over monthly and management believes the cost approximates market value. Accordingly, these volumes are valuedat market prices.

7. Property, Plant and Equipment

Pipeline, property, plant, and equipment are stated at cost less accumulated depreciation. The cost of property additions includes labor and materials,applicable overhead and payroll−related costs. Additions and improvements that add to the productive capacity or extend the useful life of the asset arecapitalized. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are charged to expense as incurred. Upon dispositionor retirement of pipeline components or gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gasplants or other property and equipment are retired or sold, any gain or loss is included in operations.

Depreciation of the gathering pipeline systems, gas plants, and processing equipment is provided using the straight−line method based on an estimateduseful life of primarily 20 years.

8. Federal and State Income Taxes

The Company is organized under the provisions of the Texas Revised Limited Partnership Act. Accordingly, taxable income or loss, which may varysubstantially from the net income or loss reported for financial reporting purposes is generally included in the federal and state income tax returns of eachpartner.

9. Revenue Recognition

Revenue for sales of natural gas and NGLs is recognized upon delivery. Service revenue, including transportation, treating, compression and gas processing,is recognized at the time service is performed. Elk City contracts consist primarily of transportation contracts and keep−whole arrangements. Undertransportation contracts, the Company receives a fee for transporting gas through its system. The revenue earned from transportation contracts is directlyrelated to volume of natural gas transported through the system and is not directly dependent on commodity prices. Under keep−whole arrangements, theCompany gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs at market prices to an affiliated company.

10. Shipping and Handling Costs

In accordance with the Emerging Issues Task Force Issue 00−10, “Accounting for Shipping and Handling Fees and Costs,” the Company classified feesdeducted from payments to producers for compression and treating of gas as revenue.

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11. Asset Retirement Obligation

The Company accounts for its asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, “Accounting for AssetRetirement Obligations” (SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in theperiod in which it incurs a legal obligation for the retirement of tangible long−lived assets, typically at the time the assets are placed into service. Acorresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, any changes in the amount of the liabilityresulting from the passage of time and revisions to either the timing or amount of estimated cash flows would be recognized prospectively.

The Company has determined that it is obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain ofits assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, futureretirement costs, future inflation rates and the credit−adjusted risk−free interest rates. However, the Company is not able to reasonably determine the fairvalue of the asset retirement obligations as of August 31, 2004, because the settlement dates are indeterminable. An asset retirement obligation will berecorded in the periods the settlement dates can reasonably determined.

12. Impairment of Long−lived Assets

Long−lived assets, including property, plant and equipments are reviewed for impairment whenever facts and circumstances indicate impairment may bepresent. When impairment indicators are present, the Company evaluates whether the assets in question are able to generate sufficient cash flows to recovertheir carrying value on an undiscounted basis. If an asset is deemed to be impaired, the amount of impairment is determined as the amount by which the netcarrying value exceeds discounted estimated net cash flows.

C — ACQUISITION

In October 2002, La Grange purchased certain operating assets from Aquila, primarily consisting of natural gas gathering, treating and processing assets inTexas and Oklahoma, for $264 million in cash. At the closing of the acquisition, approximately $33 million of the purchase price was allocated to the ElkCity assets based on the relative fair value of all assets acquired.

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The assets acquired and purchase price allocation were as follows:

Elk City Assets

Materials and supplies $ 63Property, plant and equipment 33,070Accrued expenses (260)

$ 32,873

D — PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, at cost, consisted of the following:

EstimatedUseful Lives

(Years)

Balance atAugust 31,

2004

Balance atAugust 31,

2003

Midstream pipelines and equipment 20 $ 45,445 $ 36,574Midstream right of way 20 903 103Linepack N/A 48 48Construction in progress N/A 901 3,443Other 5 195 137

Total 47,492 40,305Accumulated depreciation and amortization (3,938) (1,589)

Property, plant and equipment, net $ 43,554 $ 38,716

E — RELATED PARTY TRANSACTIONS

The Company entered into various types of transactions with La Grange, or its subsidiaries, for the year ended August 31, 2004 and eleven months endedAugust 31, 2003. The Company sold the majority of natural gas gathered and NGLs produced by the Company to La Grange or its subsidiaries. La Grangepurchased the gas and NGLs at an index based price. Additionally, the Company reimbursed La Grange for certain employees who provided services to theCompany and for other costs (primarily general and administrative expense) related to the Company’s operations. La Grange also provided working capitalnecessary for the operations of the Company.

The following table summarizes transactions for the periods presented:


Eleven MonthsEnded

August 31, 2003

Natural gas sales to affiliated companies $ 77,169 $ 60,380NGLs sales to affiliated companies 46,151 24,454Compression services from affiliated company 91 —Allocated costs from affiliated companies 2,663 2,887Working capital from affiliated companies (3,185) (11,168)Transfers of property, plant and equipment from affiliated companies 2,288 32,873

The related party receivable due from La Grange was $22,305 and $7,121 at August 31, 2004 and August 31, 2003, respectively.

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F — MAJOR CUSTOMERS AND SUPPLIERS

The Company sold 91.1% and 91.8% of natural gas and NGLs produced to ETC Marketing, Ltd., a subsidiary of La Grange, for the year ended August 31,2004 and for the eleven months ended August 31, 2003, respectively.

For the year ended August 31, 2004 and the eleven months ended August 31, 2003, the Company had gross purchases as a percentage of cost of sales fromnonaffiliated major suppliers as follows:


Eleven MonthsEnded

August 31, 2003

St. Mary Operating Company 22.8% 14.1%Samson Resources Company 18.2% 23.4%Stephens Production Company 12.8% 8.8%

Management believes that the diversification of suppliers is sufficient to enable the Company to purchase all of its supply needs at market prices without amaterial disruption of operations if supplies are interrupted from any of the Company’s existing sources. Although no assurances can be given that supplieswill be readily available in the future, we expect a sufficient supply to continue to be available.

G — RETIREMENT AND BENEFITS

La Grange has a defined contribution plan for virtually all employees with discretionary matching. Pursuant to the plan, employees of the Company candefer a portion of their compensation and contribute it to a deferred account. La Grange did not elect to match contributions to this plan during the yearended August 31, 2004 and the eleven months ended August 31, 2003. Therefore, no expense related to the plan is recorded in the accompanying financialstatements.

H — COMMITMENTS AND CONTINGENCIES

1. Lease Obligations

The Company has operating leases for compressors under noncancelable agreements. Future annual minimum lease payments for each of the next five yearsand thereafter as of August 31, 2004 are as follows:

Year ending August 31:2005 $ 5222006 5222007 5222008 5222009 500After 2009 72

$ 2,660

Rental expense relating to operating leases was $675 and $555 for the year ended August 31, 2004 and eleven months ended August 31, 2003, respectively.

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2. Litigation

The Company is involved in various lawsuits, claims and regulatory proceedings incidental to its business. In the opinion of management, the outcome ofsuch matters will not have a material adverse effect on the Company’s financial position or results of operations.

3. Environmental

The Company’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation atoperating facilities and waste disposal sites. Although the Company believes its operations are in substantial compliance with applicable environmental lawsand regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance thatsignificant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws,regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantialcosts and liabilities. Accordingly, the Company has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupationalhealth, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financialliability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processingbusiness, as it is with other entities engaged in similar businesses.

In conjunction with the acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila, Aquila, Inc. agreed toindemnify La Grange Acquisition, L.P. for any environmental liabilities from those operations prior to October 1, 2002.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, thetiming and extent of remediation, the determination of the Company’s liability in proportion to other parties, improvements in cleanup technologies and theextent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results ofoperations for any single period, the Company believes that such costs will not have a material adverse effect on its financial position. Elk City did notaccrue for environmental liabilities as of August 31, 2004 or 2003.

I — SUBSEQUENT EVENT

On April 14, 2005, Elk City’s parent company completed the sale of the Company to Atlas Pipeline Partners, L.P. for $190 million in cash, subject to certainadjustments as defined in the purchase and sale agreement.

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ETC OKLAHOMA PIPELINE, LTD.BALANCE SHEETFebruary 28, 2005

(unaudited)(in thousands)

ASSETS

CURRENT ASSETS:Cash $ —Receivables —

Trade 2,294Related parties 27,671Exchanges 716

Materials and supplies 63Other current assets 497

Total current assets 31,241

PROPERTY, PLANT AND EQUIPMENT 50,004ACCUMULATED DEPRECIATION (5,243)

PROPERTY, PLANT AND EQUIPMENT, net 44,761

Total assets $76,002

LIABILITIES AND PARTNERS’ CAPITALCURRENT LIABILITIES:Payables —

Trade $23,206Exchanges 209

Accrued expenses 162

Total current liabilities 23,577

COMMITMENTS AND CONTINGENCIES (See Note D)

PARTNERS’ CAPITAL:Limited partner 52,373General partner 52

Total partners’ capital 52,425

Total liabilities and partners’ capital $76,002

The accompanying notes are an integral part of this financial statement.

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ETC OKLAHOMA PIPELINE, LTD.INCOME STATEMENTS


Six MonthsEnded

February 28,2005

Six MonthsEnded

February 29,2004

OPERATING REVENUE:Third party $ 6,841 $ 5,138Related party 77,355 54,789

Total revenue 84,196 59,927

COSTS AND EXPENSES:Cost of products sold 74,330 52,757Operating 2,624 2,297General and administrative 1,437 1,331Depreciation and amortization 1,236 1,076

Total costs and expenses 79,627 57,461

NET INCOME $ 4,569 $ 2,466


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ETC OKLAHOMA PIPELINE, LTD.STATEMENTS OF CASH FLOWS


Six MonthsEnded

February 28,2005

Six MonthsEnded

February 29,2004

CASH FLOWS FROM OPERATING ACTIVITIES:Net income $ 4,569 $ 2,466Adjustments to reconcile net income to net cash provided by operating activities —

Depreciation and amortization 1,236 1,076Loss on disposal of assets — 3Changes in operating assets and liabilities —

Receivables (1,024) (521)Related party receivables (12,560) (21,586)Other current assets (497) 47Payables 3,402 11,764Accrued expenses (415) (402)

Net cash used in operating activities (5,289) (7,153)

CASH FLOWS FROM INVESTING ACTIVITIES:Additions to property, plant and equipment (1,905) (2,545)Proceeds from sale of assets — 72

Net cash used in investing activities (1,905) (2,473)

CASH FLOWS FROM FINANCING ACTIVITIES:Working capital from parent 7,194 9,626

Net change in cash — —Cash beginning of year — —

Cash end of year $ — $ —

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:Non−cash asset contribution $ 538 $ 2,288

Cash paid for interest $ — $ —

Cash paid for income taxes $ — $ —


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ETC OKLAHOMA PIPELINE, LTD.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Six months ended February 28, 2005


ETC Oklahoma Pipeline, Ltd. (Elk City or the Company) is a Texas limited partnership. LG PL, LLC, a wholly−owned subsidiary of La GrangeAcquisition, L.P. (La Grange) owns a 0.1% general partner interest and La Grange Acquisition, L.P. owns a 99.9% limited partner interest. Elk City owns anatural gas gathering pipeline system and gas processing plant in Oklahoma. These assets are referred to herein as “the Elk City system.”

The Elk City system is a 318−mile gathering system located in western Oklahoma that gathers, compresses, treats and processes natural gas from theAnadarko Basin. The Elk City system also includes the Elk City processing plant and one treating facility. The Elk City system is connected, either directlyor indirectly, to six major interstate and intrastate natural gas pipelines providing access to natural gas markets throughout the United States. The Elk Citysystem has a processing capacity of approximately 130 million cubic feet per day (MMcf/d).



The interim financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“USGAAP”) and on the same basis as the audited financial statements for the year ended August 31, 2004. Certain information and footnote disclosuresnormally included in annual financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC.Because the interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction withthe audited financial statements and related notes for the year ended August 31, 2004. The results of operations for an interim period may not give a trueindication of results for a full year. There are no other components of comprehensive income other than net income.

2. Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management tomake estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of thefinancial statements and the reported amounts of revenue and expenses during the reporting period. The natural gas industry conducts its business byprocessing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results areestimated using volume estimates and market prices. Any difference between estimated results and actual results are recognized in the following month’sfinancial statements. Management believes that the operating results estimated for the six months ending February 28, 2005 and February 29, 2004 representthe actual results in all material respects.

Some of the other more significant estimates made by management include, but are not limited to the useful lives for depreciation and amortization, andgeneral business reserves. Actual results could differ from those estimates.

3. Cash

La Grange provides cash to the Company for working capital and capital expenditures. Cash transfers are recorded through related party receivables andpayables. Cash receipts of the Company are immediately transferred to La Grange to reduce the intercompany balance with LaGrange.

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Elk City deals with counter parties that are typically either investment grade (Standard & Poors BBB or higher) or are otherwise secured with a letter ofcredit or other form of security (corporate guaranty or prepayment). Management reviews accounts receivable balances each week. Credit limits areassigned and monitored for all counter parties. The majority of payments are due on the 25th of the month following delivery.

Management closely monitors credit exposure for potential doubtful accounts. Management believes that an occurrence of bad debt is unlikely; therefore, anallowance for doubtful accounts was not deemed necessary at February 28, 2005. Bad debt expense is recognized at the time an account is deemeduncollectible. An account receivable will be written off in the event a counter party files for bankruptcy protection or the account is turned over forcollection and the collector deems the account uncollectible. No bad debt expense was recorded during the six months ended February 28, 2005 or sixmonths ended February 29, 2004.

C — RELATED PARTY TRANSACTIONS

The Company entered into various types of transactions with La Grange, or its subsidiaries for the six months ended February 28, 2005 and February 29,2004.

The following table summarized transactions for the six month periods ended February 28, 2005 and February 29, 2004:

2005 2004

Natural gas sales to affiliated companies $47,886 $33,957NGLs sales to affiliated companies 29,469 20,832Compression services from affiliated company 207 —Allocated costs from affiliated companies 1,437 1,329Working capital to (from) related companies 4,009 (1,542)Transfer of property, plant and equipment from related parties 539 2,288

The related party receivable due from La Grange was $27,671 as of February 28, 2005.

D — COMMITMENTS AND CONTINGENCIES

1. Litigation


2. Environmental

The Company’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation atoperating facilities and waste disposal sites. Although the Company believes its operations are in substantial compliance with applicable environmental lawsand regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance thatsignificant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws,regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantialcosts and liabilities. Accordingly, the Company has adopted policies, practices, and procedures in the

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areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent materialenvironmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or otherdamage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.

In conjunction with the acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila, Aquila, Inc. agreed toindemnify La Grange Acquisition, L.P. for any environmental liabilities from those operations prior to October 1, 2002.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, thetiming and extent of remediation, the determination of the Company’s liability in proportion to other parties, improvements in cleanup technologies and theextent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results ofoperations for any single period, the Company believes that such costs will not have a material adverse effect on its financial position. Elk City did notaccrue for environmental liabilities as of February 28, 2005.

E — SUBSEQUENT EVENT

On April 14, 2005, Elk City’s parent company completed the sale of the Company to Atlas Pipeline Partners, L.P. for $190 million in cash, subject to certainadjustments as defined in the purchase and sale agreement.

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Report of Independent Registered Public Accounting Firm

Board of Directors andAtlas Pipeline Partners, L.P.

We have audited the accompanying carve−out statements of income and changes in parent’s equity and cash flows of the Elk City System (a division of theAquila Gas Pipeline Corporation), for the year ended September 30, 2002. These financial statements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not requiredto have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control overfinancial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on theeffectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made bymanagement, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the carve−out financial statements referred to above present fairly, in all material respects, the results of operations of the Elk City System ofAquila Gas Pipeline Corporation for the year ended September 30, 2002, in conformity with accounting principles generally accepted in the United States ofAmerica.

/s/Grant Thornton LLPCleveland, OhioApril 25, 2005

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THE ELK CITY SYSTEMCARVE−OUT STATEMENT OF INCOME AND CHANGES

IN PARENT’S EQUITY IN DIVISIONFor the year ended September30, 2002

(in thousands)

OPERATING REVENUE:Third party $ 5,599Related party 46,643

Total revenue 52,242COSTS AND EXPENSES:Cost of products sold 41,610Operating 3,881General and administrative 1,389Depreciation and amortization 3,811Asset impairment 12,850

Total costs and expenses 63,541

LOSS FROM OPERATIONS (11,299)

OTHER INCOME:Gain on disposal of assets 14

LOSS BEFORE INCOME TAXES (11,285)

INCOME TAX BENEFIT (4,439)

NET LOSS (6,846)Parent’s beginning equity in division 11,763

Parent’s ending equity in division $ 4,917


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THE ELK CITY SYSTEMCARVE−OUT STATEMENT OF CASH FLOWS

For the year ended September30, 2002(in thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:Net loss $ (6,846)Adjustments to reconcile net loss to net cash provided by operating activities —

Depreciation and amortization 3,811Asset impairment 12,850Deferred income taxes (4,864)Other, net (15)Changes in operating assets and liabilities —

Receivables (1,726)Materials and supplies 148Other current assets (34)Payables 942Related party payables 5,167Accrued expenses 49Income taxes payable 425

Net cash provided by operating activities 9,907

CASH FLOWS FROM INVESTING ACTIVITIES:Additions to property, plant and equipment (5,045)Proceeds from sale of assets 115

Net cash used in investing activities (4,930)

CASH FLOWS FROM FINANCING ACTIVITIES:Working capital from parent (4,977)

Net cash used in financing activities (4,977)

Net change in cash and cash equivalents —Cash and cash equivalents, beginning of year —

Cash and cash equivalents, end of year $ —


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THE ELK CITY SYSTEMNOTES TO CARVE−OUT FINANCIAL STATEMENTS

Year ended September 30, 2002(in thousands)


Aquila Gas Processing Corporation (AGP), a Delaware Corporation and a wholly−owned subsidiary of Aquila Gas Pipeline Corporation (Aquila), ownedthe Elk City natural gas gathering pipeline system and gas processing plant in Oklahoma. Collectively, those assets are referred to herein as the Elk CitySystem. The Elk City System is considered a business as defined in the rules and regulations of the U.S. Securities and Exchange Commission and issometimes referred to herein as the “Company”.

The Elk City system, a 318−mile gathering system located in western Oklahoma, gathers, compresses, treats and processes natural gas from the AnadarkoBasin. The Elk City System also includes the Elk City processing plant and one treating facility. The Elk City System is connected, either directly orindirectly, to six major interstate and intrastate natural gas pipelines providing access to natural gas markets throughout the United States. The Elk CitySystem has a processing capacity of approximately 130 million cubic feet per day (MMcf/d).



The financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America.The accompanying financial statements present the operations and cash flows of the Elk City System on a carve−out basis. Accordingly, the carve−outfinancial statements reflect a reasonable allocation of the costs historically incurred by AGP.

2. Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management tomake estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of thefinancial statements and the reported amounts of revenue and expenses during the reporting period.

Significant estimates made by management include, but are not limited to the useful lives for depreciation and amortization, and general business reserves.Actual results could differ from those estimates.

3. Impairment of Long−lived Assets

The Company evaluates the carrying value of long−lived assets to be held and used when events and circumstances warrant such a review. The carryingvalue of long−lived assets would be considered impaired when the projected undiscounted cash flows are less than carrying value. In that event, a losswould be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by available marketvaluations, or, if applicable, discounted cash flows.

As a result of the sale to La Grange (See Note H), the Company recorded an impairment of $12,850 for the year ended on September 30, 2002, to writedown the Elk City assets to their net realizable value.

4. Revenue Recognition

Revenue for sales of natural gas and natural gas liquids (NGLs) is recognized upon delivery. Service revenue, including transportation, treating,compression and gas processing, is recognized at the time

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service is performed. Elk City System contracts consist primarily of transportation contracts and keep−whole arrangements. Under transportation contracts,the Company receives a fee for transporting gas through its system. The revenue earned from transportation contracts is directly related to volume of naturalgas transported through the system and is not directly dependent on commodity prices. Under keep−whole arrangements, the Company gathers natural gasfrom the producer, processing the natural gas and selling the resulting NGLs at market prices to an affiliated company.

5. Shipping and Handling Costs

In accordance with the Emerging Issues Task Force Issue 00−10, “Accounting for Shipping and Handling Fees and Costs,” the Company classifies feesdeducted from payments to producers for compression and treating of gas as revenue.

6. Commodity Risk Management

In 1999, Aquila Gas Pipeline transferred all of its energy trading operations and management thereof to Aquila Energy Market (AEM), a wholly ownedsubsidiary of Aquila, Inc. AEM enters into forward physical contracts with third parties for the benefit of Aquila and where deemed necessary entered intointercompany financial derivative positions (e.g., swaps, futures and options) with Aquila and other affiliates to assist them in managing their exposures.Thus, Aquila has forward physical contracts with third parties and financial derivative positions with AEM and affiliates. This activity was not pushed downto the carve−out financial statements of Elk City.

7. Stock Compensation

Some of the Company’s employees received stock options in Aquila. As permitted under accounting principles generally accepted in the United States ofAmerica, Aquila elected to account for the options under Accounting Principles Board Opinion No. 25, and because the options strike price was equal to orgreater than the fair value at the date of the grant, no compensation expense was recognized for the year ended September 30, 2002. As these were Aquilaoptions, the Company does not have full access to the information necessary to disclose what compensation expense would have been, had Aquila accountedfor the options under Statement of Financial Accounting Standards No. 123, Accounting for Stock−Based Compensation, which requires compensationexpense be recognized for the fair value of the options at the date of grant. La Grange Acquisition does not have a stock option plan in place for itsemployees.

8. Federal and State Income Taxes

The Elk City System was included in the consolidated federal income tax returns filed by Aquila. Accordingly, all tax balances were ultimately settledthrough Aquila. The Company had generally accounted for its taxes on a stand−alone or separate return basis (see Note D). Periodically, taxes payable weresettled through the intercompany accounts with Aquila and were not funded in cash.

The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (StatementNo. 109). Statement No. 109 requires that deferred tax assets and liabilities be established for the basis differences between the reported amounts of assetsand liabilities for financial reporting purposes and income tax purposes.

9. Asset Retirement Obligation

The Company accounts for its asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, Accounting for AssetRetirement Obligations (SFAS No. 143). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in

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the period in which it incurs a legal obligation for the retirement of tangible long−lived assets, typically at the time the assets are placed into service. Acorresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement, any changes in the amount of the liabilityresulting from the passage of time and revisions to either the timing or amount of estimated cash flows would be recognized prospectively.

The Company has determined that it is obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain ofour assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, futureretirement costs, future inflation rates and the credit−adjusted risk−free interest rates. However, the Company is not able to reasonably determine the fairvalue of the asset retirement obligations as of September 30, 2002, because the settlement dates are indeterminable. An asset retirement obligation will berecorded in the periods in which the settlement dates can reasonably be determined.

C — RELATED PARTY TRANSACTIONS

The Company entered into various types of transactions with Aquila for the year ended September 30, 2002. The Company sold the majority of natural gasand NGLs produced to Aquila. Additionally, the Company reimbursed Aquila for certain employees who provided services to the Company and for othercosts (primarily general and administrative expense) related to the Company’s operations. Aquila also provided the working capital necessary for theoperations of the Company.

The following table summarized transactions for the year ended September 30, 2002:

Natural gas sales to affiliated companies $16,391NGLs sales to affiliated companies 30,252Allocated costs from affiliated companies 1,389Working capital to affiliated companies 3,732

D — INCOME TAXES

A reconciliation between the expected tax computed using the US federal statutory income tax rate and the provision for income taxes is as follows:

2002

Statutory federal income tax (35%) $(3,950)State and local income taxes — net of federal income tax effect (4.3%) (489)

Total $(4,439)

E — RETIREMENT AND BENEFITS

For the year ended September 30, 2002, certain Aquila employees received stock options to purchase Aquila’s common stock. As permitted under generallyaccepted accounting principles, Aquila elected to account for the options under Accounting Principles Board Opinion No. 25, and because the options strikeprice was equal to or greater than the fair value at the date of grant, no compensation expense was recognized. As these were Aquila, Inc. options, theCompany does not have full access to the information necessary to disclose what compensation would have been, had Aquila accounted for the optionsunder Statement of Financial Accounting Standards No. 123, “Accounting for

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Stock−Based Compensation”, which requires compensation expense be recognized for the fair value of the options at the date of grant. The Company doesnot have a stock option plan in place for its employees.

Aquila had a defined contribution plan for virtually all employees. Pursuant to the plan, employees of the Company can defer a portion of theircompensation and contribute it to a deferred account. Aquila’s matching contribution to the plan for the Company employees was $34 for the year endedSeptember 30, 2002.

Aquila had a stock contribution plan under which eligible employees received a Company contribution of 3% of their base income in Aquila’s commonstock. The Company’s expense associated with this plan for the Company employees for the year ended September 30, 2002 was $19.

F — COMMITMENTS AND CONTINGENCIES

1. Litigation


2. Environmental

The Company’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation atoperating facilities and waste disposal sites. Although the Company believes its operations are in substantial compliance with applicable environmental lawsand regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance thatsignificant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws,regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantialcosts and liabilities. Accordingly, the Company has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupationalhealth, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financialliability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processingbusiness, as it is with other entities engaged in similar businesses.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, thetiming and extent of remediation, the determination of the Company’s liability in proportion to other parties, improvements in cleanup technologies and theextent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results ofoperations for any single period, the Company believes that such costs will not have a material adverse effect on its financial position. Elk City did notaccrue for environmental liabilities as of September 30, 2002.

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G — MAJOR CUSTOMERS AND SUPPLIERS

The Company sold 89.3% of natural gas and NGLs produced to Aquila for the year ended September 30, 2002.

For the year ended September 30, 2002, the Company had gross purchases as a percentage of cost of sales from nonaffiliated major suppliers as follows:

St. Mary Operating Company 19.8%Exxon Company, U.S.A 10.7%

Management believes that the diversification of suppliers is sufficient to enable the Company to purchase all of its supply needs at market prices without amaterial disruption of operations if supplies are interrupted from any of the Company’s existing sources. Although no assurances can be given that supplieswill be readily available in the future, we expect a sufficient supply to continue to be available.

H — SUBSEQUENT EVENT

In October 2002, La Grange Acquisition, L.P. purchased the Elk City System from Aquila.

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Report of Independent Certified Public Accountants

Board of DirectorsSpectrum Field Services, Inc.

We have audited the accompanying balance sheets of Spectrum Field Services, Inc. (a Delaware corporation) as of December 31, 2003 and 2002, and the relatedstatements of operations, comprehensive income (loss), changes in shareholders’ equity and cash flows for each of the three years in the period ended December31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financialstatements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan andperform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for ouropinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Spectrum Field Services, Inc. as ofDecember 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, inconformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLPTulsa, OklahomaMay 17, 2004(except with respect to the mattersdiscussed in Note J, as to which thedate is June 10, 2004)

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Spectrum Field Services, Inc.Balance sheets

December 31, 2003 and 2002(in thousands, except share data)

2003 2002

ASSETSCURRENT ASSETS:Cash $ 173 $ 478Accounts receivable 8,473 7,554Inventories 179 553Prepaid expenses and other 108 200Income tax receivable — 207Security deposits 257 —Deferred income taxes 10 —

Total current assets 9,200 8,992

PROPERTY, PLANT AND EQUIPMENT, net 47,050 47,774

DEFERRED INCOME TAXES 1,644 —

SECURITY DEPOSITS 1,481 225

OTHER ASSETS, net 250 1,159

Total assets $59,625 $58,150

LIABILITIES AND SHAREHOLDERS’ EQUITYCURRENT LIABILITIES:Accounts payable $ 4,800 $ 1,428Accrued producer payables 6,470 6,109Accrued liabilities 129 234Hedge liabilities 338 719Current maturities of long−term debt 4,995 3,076

Total current liabilities 16,732 11,566

LONG−TERM DEBT, less current maturities 39,117 35,200

PREFERRED DIVIDENDS PAYABLE 2,129 1,075

DEFERRED INCOME TAXES — 2,063

COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ EQUITY:Preferred stock, $0.01 par value; 8.0% cumulative; 20,000,000 shares authorized; 13,856,047 shares of Series A preferred stock issued; 11,052,304 shares outstanding at December 31, 2003 and 2002 13,856 13,856Common stock, $0.01 par value; 5,000,000 shares authorized; 2,722,194 and 2,712,194 shares issued; 2,084,891 and 2,074,891 shares outstanding at December 31, 2003 and 2002, respectively 27 27Additional paid−in capital 3,149 3,043Retained earnings (accumulated deficit) (5,279) 1,729Treasury stock – preferred, at cost (3,758) (3,758)Treasury stock – common, at cost (6,252) (6,252)Deferred compensation (43) (70)Accumulated other comprehensive loss, net of tax of $32 and $201 in 2003 and 2002, respectively (53) (329)

Total shareholders’ equity 1,647 8,246

Total liabilities and shareholders’ equity $59,625 $58,150

The accompanying notes are an integral part of these balance sheets.

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Spectrum Field Services, Inc.Statements of operations

For the years ended December 31, 2003, 2002 and 2001(in thousands)

2003 2002 2001

SALES OF NATURAL GAS AND LIQUIDS $ 98,772 $65,760 $86,316

COST OF NATURAL GAS AND LIQUIDS 78,827 49,659 64,160

Gross profit 19,945 16,101 22,156

OPERATING EXPENSE 6,262 6,954 8,891

GENERAL AND ADMINISTRATIVE EXPENSE 4,322 2,374 2,947

IMPAIRMENT OF PROPERTY, PLANT AND EQUIPMENT — 1,889 —

DEPRECIATION 16,050 4,407 2,779

(LOSS) INCOME FROM OPERATIONS (6,689) 477 7,539

INTEREST EXPENSE (2,725) (2,659) (3,423)

OTHER (EXPENSE) INCOME, net (843) 10 299

(LOSS) INCOME BEFORE INCOME TAXES (10,257) (2,172) 4,415

INCOME TAX (BENEFIT) PROVISION (4,303) (500) 1,677

NET (LOSS) INCOME (5,954) (1,672) 2,738

PREFERRED STOCK DIVIDENDS 1,054 752 643

NET (LOSS) INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS $ (7,008) $ (2,424) $ 2,095


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Spectrum Field Services, Inc.Statements of comprehensive income (loss)As of December 31, 2003, 2002 and 2001

(in thousands)

2003 2002 2001

NET (LOSS) INCOME $(5,954) $(1,672) $ 2,738

OTHER COMPREHENSIVE INCOME (LOSS):Change in value of derivative instruments, net of tax of $169, $(201) and $0 in 2003, 2002 and 2001, respectively 276 (329) —

COMPREHENSIVE (LOSS) INCOME $(5,678) $(2,001) $ 2,738

RECONCILIATION OF ACCUMULATED OTHER COMPREHENSIVE LOSS:Balance, beginning of period $ (329) $ — $ —

Current period reclassification to earnings, net of tax of $793, $5 and $0 in 2003, 2002 and 2001, respectively 1,293 7 —Current period change, net of tax of $623, $206 and $0 in 2003, 2002 and 2001, respectively (1,017) (336) —

Balance, end of period $ (53) $ (329) $ —


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Spectrum Field Services, Inc.Statements of changes in shareholders’ equity

For the years ended December 31, 2003, 2002 and 2001(in thousands, except share data)

Preferred Stock Common StockAdditional

Paid−in

RetainedEarnings

(Accumulated

Treasury Stock

Deferred

AccumulatedOther

ComprehensiveShares Amount Shares Amount Capital Deficit) Preferred Common Compensation Loss Total

Balance, December 31, 2000 10,886,576 $ 10,887 2,211,109 $ 22 $ 2,643 $ 2,058 $ — $ — $ (665) $ — $ 14,945Repurchase of shares — — — — — — (3,754) (5,932) — — (9,686)Net income available to commonshare− holders — — — — — 2,095 — — — — 2,095Vesting of restricted commonstock — — — — — — — — 166 — 166Vesting of phantom units — — — — 112 — — — — — 112

Balance, December 31, 2001 10,886,576 10,887 2,211,109 22 2,755 4,153 (3,754) (5,932) (499) — 7,632Repurchase of restricted commonstock — — — — — — — (320) — — (320)Repurchase of preferred shares — — — — — — (4) — — — (4)Issuance of stock 2,969,471 2,969 545,529 5 540 — — — — — 3,514Net loss attributable to commonshare− holders — — — — — (2,424) — — — — (2,424)Vesting of restricted commonstock — — — — — — — — 289 — 289Cancellation of unvestedrestricted common stock — — (44,444) — (140) — — — 140 — —Net change in accumulated othercompre− hensive loss — — — — — — — — — (329) (329)Termination of phantom unit plan — — — — (112) — — — — — (112)

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Spectrum Field Services, Inc.Statements of changes in shareholders’ equity – continued

For the years ended December 31, 2003, 2002 and 2001(in thousands, except share data)

Preferred Stock Common StockAdditional

Paid−in

RetainedEarnings

(Accumulated

Treasury Stock

Deferred

AccumulatedOther

ComprehensiveShares Amount Shares Amount Capital Deficit) Preferred Common Compensation Loss Total

Balance, December 31, 2002 13,856,047 $ 13,856 2,712,194 $ 27 $ 3,043 $ 1,729 $ (3,758) $ (6,252) $ (70) $ (329) $ 8,246Issuance of restricted stock — — 10,000 — 32 — — — (32) — —Net loss attributable to commonshare− holders — — — — — (7,008) — — — — (7,008)Vesting of restricted commonstock — — — — — — — — 59 — 59Compensation expense for stockoptions — — — — 74 — — — — — 74Net change in accumulated othercompre− hensive loss — — — — — — — — — 276 276

Balance, December 31, 2003 13,856,047 $ 13,856 2,722,194 $ 27 $ 3,149 $ (5,279) $ (3,758) $ (6,252) $ (43) $ (53) $ 1,647


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Spectrum Field Services, Inc.Statements of cash flows

For the years ended December 31, 2003, 2002 and 2001(in thousands)

2003 2002 2001

CASH FLOWS FROM OPERATING ACTIVITIES:Net loss (income) $ (5,954) $(1,672) $ 2,738Adjustments to reconcile net loss to net cash provided by operating activities—

Depreciation and amortization of loan origination fees 16,364 4,718 3,127Deferred income taxes (3,717) (196) 1,870Noncash compensation expense 133 177 278Unrealized (gain) loss on ineffective hedges (105) 189 —Loss (gain) on sale of assets 456 (10) —Impairment of property, plant and equipment — 1,889 —Noncash interest expense 1,188 946 386Changes in assets and liabilities—

Accounts receivable (919) (2,505) 1,474Inventories 374 201 (287)Prepaid expenses and other 92 (45) —Income tax receivable 207 816 (973)Other assets (749) (989) (160)Accounts payable 3,372 (29) (1,204)Accrued producer payables 361 2,426 (4,829)Accrued liabilities (105) 40 (917)

Net cash provided by operating activities 10,998 5,956 1,503

CASH FLOWS FROM INVESTING ACTIVITIES:Capital expenditures (17,410) (2,844) (5,949)Proceeds from sale of assets 1,628 169 —

Net cash used in investing activities (15,782) (2,675) (5,949)

CASH FLOWS FROM FINANCING ACTIVITIES:Borrowings from long−term debt 6,600 284 3,850Payments on long−term debt (4,510) (5,848) (3,000)Borrowings under line of credit 8,208 1,700 13,350Payments on line of credit (5,650) (6,050) (9,050)Proceeds from issuance of stock — 3,514 —Repurchase of stock — (324) —Borrowings from subordinated notes — 3,515 —Other — (5) —Dividends paid — — (322)Loan origination fees (169) (98) (50)

Net cash provided by (used in) financing activities 4,479 (3,312) 4,778

NET CHANGE IN CASH (305) (31) 332CASH, beginning of period 478 509 177

CASH, end of period $ 173 $ 478 $ 509

SUPPLEMENTAL INFORMATION:Cash paid for interest $ 1,076 $ 1,384 $ 3,226

Cash paid for income taxes $ — $ — $ 774

Noncash financing activity – paid in kind interest $ 1,188 $ 946 $ 386

Noncash financing activity – issuance of restricted common stock $ 32 $ — $ —

Noncash financing activity – capital lease $ — $ — $ 125

Noncash financing activity – repurchase of preferred and common stock and extinguishments of subordinated notes (Note A) $ — $ — $13,000



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Spectrum Field Services, Inc.Notes to financial statements

December 31, 2003, 2002 and 2001(in thousands, except share data)

A — OPERATIONS AND ORGANIZATION

Spectrum Field Services, Inc. (the Company), was incorporated in Delaware on May 8, 2000. The Company was formed to acquire and operate natural gasprocessing plants and gathering systems in Velma, Oklahoma and Kingman, Kansas.

On February 28, 2001, the Company entered into an agreement to repurchase the interest of one of the Company’s equity investors, which was also a majorcustomer of the Company. The agreement resulted in the Company forgiving $13,000 in accounts receivable owed by the shareholder at February 28, 2001,in exchange for the retirement of the outstanding subordinated debt owed to the shareholder, the repurchase of all of the shareholder’s common and Series Apreferred stock, and the retirement of the shareholder’s outstanding stock warrant. This transaction was treated as a noncash transaction for presentation inthe statement of cash flows. The Company refinanced the subordinated debt with additional borrowings of long−term debt.

On August 1, 2003, the Company sold all of the assets of the Company’s natural gas processing plant located in Kingman, Kansas for $1,200 with aneffective date of April 1, 2003. The value of the plant was written down by $1,889 as of December 31, 2002, in contemplation of the transaction inaccordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long−Lived Assets (SFAS 144). In2003, an additional loss of $215 was recorded which related to the sale of the plant. The additional loss was recorded as other expense in the Company’sstatement of operations.

On December 30, 2003, the Company engaged Lehman Brothers to explore strategic alternatives for the Company including a merger, sale or othertransactions involving the stock or assets of the Company.

B — SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL


The Company grants credit to its customers for the purchase of natural gas and natural gas liquids. Accounts receivable consist of amounts billed tocustomers and an accrual for sales not yet billed. The Company writes off accounts receivable when management believes the receivables to beuncollectible. A summary of accounts receivable at December 31 is as follows:

2003 2002

Customer receivables $ 119 $ 44Accrued sales 8,354 7,510

$ 8,473 $ 7,554

2. Inventories

The Company’s inventories are primarily comprised of replacement pipe, natural gas and natural gas liquids and are stated at the lower of cost or market.

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A summary of inventories at December 31 is as follows:

2003 2002

Replacement pipe $ 76 $110Natural gas 65 179Natural gas liquids — 232Other 38 32

$179 $553

3. Property, Plant and Equipment

Property, plant and equipment are stated at cost. Depreciation is provided using the straight−line method over the estimated useful lives of the assets asfollows:

Buildings and improvements 7 to 39 yearsPlant, machinery and equipment 10 to 20

yearsRights of way 20 yearsOffice furniture and equipment 5 to 7 yearsAutos 5 years

Maintenance, repairs and betterments, including replacement of minor items of physical properties, are charged to expense. Major additions to physicalproperties are capitalized. The cost of the assets retired or sold is credited to the asset accounts and the related accumulated depreciation is charged to theaccumulated depreciation accounts. The gain or loss from sale or retirement of property, if any, is included in the statement of operations.

A summary of property, plant and equipment at December 31 is as follows:

2003 2002

Land $ 181 $ 181Buildings and improvements 486 287Plant, machinery and equipment 48,415 48,797Rights of way 6,313 5,079Office furniture and equipment 1,329 1,515Autos 275 242Construction in process 445 —

57,444 56,101Less− accumulated depreciation (10,394) (8,327)

$ 47,050 $47,774

4. Security Deposits

Security deposits primarily represent amounts paid by the Company to the Velma Gas Plant’s electricity provider to finance the upgrade of the electricityprovider’s facilities to accommodate the Company’s additional electricity requirements resulting from the addition of several new electric compressors at theVelma Gas Plant. The electricity provider is required to repay the amount paid by the Company over time based on the Company’s electric powerconsumption. Management projects such payments to occur over a six−year period. The Company has classified the amount expected to be received fromthe electricity provider within one year as a current asset. No interest is charged on the outstanding balance.

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5. Other Long−Term Assets

Other long−term assets consist primarily of loan origination fees and deposits made for the purchase of equipment. Loan origination fees are capitalized atcost and amortized over the term of the associated notes using the straight−line method. The following is a summary of the Company’s other assets atDecember 31:

December 31, 2003 December 31, 2002

GrossCarryingAmount

AccumulatedAmortization

GrossCarryingAmount

AccumulatedAmortization

Loan origination fees (3−5 years) $ 1,122 $ (872) $ 953 $ (558)Deposits for equipment purchases — — 750 —Other — — 14 —

Total $ 1,122 $ (872) $ 1,717 $ (558)

6. Long−Lived Assets

The Company periodically evaluates whether events and circumstances have occurred that indicate the remaining estimated useful life of long−lived assetsmay warrant revision or that the remaining balance of long−lived assets may not be recoverable. When factors indicate that long−lived assets should beevaluated for possible impairment, the Company uses an estimate of the related operation’s undiscounted cash flows over the remaining life of the assets inmeasuring whether the assets are recoverable. When undiscounted cash flows are less than book value of the assets, the required impairment is calculated asthe excess of the book value of the assets over the discounted cash flows. Impairment charges of $0, $1,889 and $0 were recorded for the years endedDecember 31, 2003, 2002 and 2001, respectively.

7. Revenue and Cost Recognition

Revenue and costs are recognized at the time the natural gas is processed and the natural gas and natural gas liquids are delivered at the tailgate of the plantto market. For 2003 and 2002, approximately 20% of the Company’s natural gas supply comes from one supplier.

8. Income Taxes

The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS109), which requires an asset and liability approach to financial accounting and reporting for income taxes. Deferred income tax assets and liabilities arecomputed for those differences that have future tax consequences using currently enacted tax laws and future rates that will apply to the periods in whichthey are expected to affect taxable income.

At December 31, 2003 and 2002, the Company had net noncurrent deferred tax assets and net noncurrent deferred tax liabilities of approximately $1,644and $2,063, respectively. The deferred tax liabilities are primarily generated due to the difference between depreciation calculated for financial reporting andincome tax purposes. The deferred tax assets relate primarily to net operating loss carryforwards and recognition of an impairment loss for financialreporting purposes in 2002. At December 31, 2003, the Company has net operating loss carryforwards of approximately $14,700, which will begin to expirein 2022. No valuation allowance has been recorded against the Company’s deferred tax asset as management expects future taxable income will be sufficientto utilize the Company’s net operating loss carryforwards.

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The Company’s 2003 income tax benefit consists of a current income tax benefit of $614 and a deferred income tax benefit of $3,689. The Company’s 2002income tax benefit consists of a current income tax benefit of $696 and a deferred income tax expense of $196. The Company’s 2001 income tax provisionconsists of a current income tax benefit of $193 and a deferred income tax expense of $1,870. The effective tax rate differs from the enacted federal incometax rate primarily due to state income taxes and tax credits.

9. Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management tomake estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of thefinancial statements and the reported amounts of revenue and expenses during the reporting period. Significant estimates include, but are not limited to,estimating accrued revenue and producer payments, evaluating the realizability of long−lived assets, and estimating the fair value of derivatives. Actualresults could differ from those estimates.

10. Reclassifications

Certain reclassifications of previously reported amounts for 2002 and 2001 have been made to conform with the 2003 presentation format. Thesereclassifications had no impact on net loss.

11. Concentration of Credit Risk

The Company extends trade credit to various companies in the natural gas and natural gas liquids market in the normal course of business. In 2003 and2002, respectively, the Company had two primary customers that accounted for approximately 87% and 96% of the Company’s sales and 80% and 83% ofthe Company’s accounts receivable at December 31, 2003 and 2002. During 2001, the Company had three primary customers (one of which was ashareholder of the Company through February 28, 2001). In 2001, sales to three customers accounted for approximately 97% of the Company’s sales.Management believes the credit worthiness of its customers mitigates the concentration risk.

12. Derivative Instruments

The Company applies the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and HedgingActivities (SFAS 133). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value.Changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifyinghedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations. Companies must formally document,designate, and assess the effectiveness of transactions that receive hedge accounting.

13. Restricted Common Stock

The Company has granted restricted common stock to certain key employees. The Company applies fixed plan accounting in accordance with AccountingPrinciples Board Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, the Company records the issuance of restricted stock as anincrease to equity with a corresponding offset to deferred compensation (presented as a reduction in equity on the balance sheet). The deferred compensationis reduced by recording compensation expense over the vesting period.

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14. Recently Issued Accounting Pronouncements

The Company accounts for expected future costs associated with its obligation to perform site reclamation and dismantle facilities of abandoned plants andpipelines under Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. If a reasonable estimate of thefair value of an abandonment obligation can be made, SFAS 143 requires the Company to record a liability (an asset retirement obligation or ARO) on thebalance sheets in other noncurrent liabilities and to capitalize the asset retirement cost in the period in which the retirement obligation is incurred. In general,the amount of an ARO and the associated costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using currentprices after discounting the future cost back to the date that the abandonment obligation was incurred using the credit−adjusted risk−free rate for theCompany. After recording these amounts, the ARO will be accreted to its future estimated value using the credit−adjusted risk−free rate and the additionalcapitalized costs will be depreciated on a straight−line basis over the productive life of the related assets. The Company has not recorded an asset retirementobligation as of December 31, 2003, as management believes the amount to be immaterial to the Company’s financial statements.

In April 2002, the FASB issued SFAS No. 145, Recission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and TechnicalCorrections. Under the provisions of SFAS No. 145, gains and losses from the extinguishment of debt generally will no longer be classified as extraordinaryitems in the statement of operations. The provisions of SFAS No. 145 related to the extinguishment of debt become effective for the Company beginning in2003. The adoption did not have a material impact on the Company’s financial position or results of operations.

In June 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which requires companies to recognizecosts associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costscovered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinuedoperation, plant closing, or other exit or disposal activity. SFAS 146 is effective for fiscal years beginning after December 31, 2002, with early applicationencouraged. The Company adopted this standard January 1, 2003. The adoption did not have a material impact on the Company’s financial position orresults of operations.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock−Based Compensation – Transition and Disclosure – an amendment of FAS 123.The standard provides additional transition guidance for companies that elect to voluntarily adopt the accounting provisions of SFAS No. 123, AccountingFor Stock−Based Compensation. SFAS No. 148 does not change the provisions of SFAS No. 123 that permit entities to continue to apply the intrinsic valuemethod of APB 25, Accounting for Stock Issued to Employees. The Company currently has no stock options outstanding to employees and already appliesthe accounting provisions of SFAS No. 123 to the stock options discussed in Note H. Accordingly, the adoption of SFAS No. 148 did not have a materialimpact on the Company’s financial position or results of operations.

In November 2002, the FASB issued Interpretation No. 45 (FIN 45), Guarantees, Including Indirect Guarantees of Indebtedness of Others. FIN 45 requiresthat upon the issuance of guarantees, the guarantor must recognize a liability for the fair value of the obligations it assumes under the guarantee. Liabilityrecognition is required on a prospective basis for guarantees that are made or modified after December 31, 2002. The adoption of FIN 45 had no impact onthe Company’s financial position or results of operations.

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In January 2003, the FASB issued Interpretation No. 46 (FIN 46), Consolidation of Variable Interest Entities, an interpretation of ARB 51. The primaryobjectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved through means other than through voting rights(variable interest entities or VIEs) and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidationapplies to an entity which either (1) the equity investors, if any, do not have a controlling financial interest or (2) the equity investment at risk is insufficientto finance that entity’s activities without receiving additional subordinated financial support from other parties. The adoption of this standard did not haveany impact on the Company’s financial position or results of operations.

In April 2003, the FASB issued Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends andclarifies financial accounting and reporting for derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedgingactivities under SFAS 133. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated afterJune 30, 2003. The Company adopted SFAS 149 as of July 1, 2003. The adoption of SFAS 149 did not have a material impact on the Company’s financialposition or results of operations.

C — DERIVATIVE INSTRUMENTS

The Company entered into certain financial swap instruments, some of which settled during the years ended December 31, 2003 and 2002, that aredesignated as cash flow hedging instruments in accordance with SFAS 133. The maturities of the instruments outstanding at December 31, 2003, are lessthan one year. The swap instruments are contractual agreements to exchange obligations of money between the buyer and seller of the instruments as naturalgas volumes during the pricing period are sold. The swaps are tied to a set fixed price for the seller and floating price determinants for the buyer priced oncertain indices at the end of the relevant trading period. The Company entered into these instruments to hedge the forecasted gas plant residue sales tovariability in expected future cash flows attributable to changes in natural gas prices. For the swaps that were settled during the year ended December 31,2003, the Company reclassified into earnings a before−tax loss of $2,086, that was previously reported in accumulated other comprehensive loss. For theswaps that were settled during the year ended December 31, 2002, the Company reclassified into earnings a before−tax gain of $12, that was previouslyreported in accumulated other comprehensive income (loss).

The Company entered into several swaps that were designed to hedge natural gas liquids prices during 2003 and 2002 that did not meet specific hedgeaccounting criteria. The Company recognized a before−tax loss of $254 and $189 related to these swaps during the years ending December 31, 2003 and2002, respectively.

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D — LONG−TERM DEBT

A summary of long−term debt at December 31 is as follows:

2003 2002

Senior Term Note payable to a bank, interest payable quarterly atLIBOR or the bank’s reference rate plus an applicable margin basedon the Company’s leverage ratio (interest rate of 4.46% atDecember 31, 2003), quarterly principal payments of approximately$1,000 through June 30, 2005, with the remaining balance due July2005 $18,850 $21,850Advancing Term Loan payable to a bank entered into July 1, 2003,interest payable quarterly at LIBOR plus 3.25% (interest rate of 4.71%at December 31, 2003), quarterly principal payments of $230 throughJune 30, 2005, with balance due July 2005 5,170 —Subordinated notes payable to shareholders, interest payable quarterly at8.00%, outstanding principal due in July 2007 15,603 14,415$12,000 revolving line of credit, interest payable monthly at PRIME plus.75% or the bank’s reference rate plus an applicable margin based onthe Company’s leverage ratio (interest rate of 4.75% at December 31,2003), outstanding principal due in July 2005 4,208 1,650Other 281 361

44,112 38,276Less− current maturities 4,995 3,076

$39,117 $35,200

Substantially all of the Company’s assets are pledged under these loan agreements. The terms of these agreements place certain financial and operatingcovenants on the Company, the most restrictive being a debt−to−capitalization ratio and a fixed charge ratio. The Company was in compliance with allcovenants at December 31, 2003.

At December 31, 2003, the Company entered into an agreement to modify the terms of the revolving line of credit. Per this agreement, the amount availableto the Company under the line of credit is increased to $12,000. However, if the Company does not consummate a sale of all or substantially all of theCompany’s assets by June 30, 2004, the total amount available under the line of credit is reduced to $6,000 and any amount owed by the Company at June30, 2004, over $6,000 must be repaid to the bank in an amount not to exceed $1,800. The remaining balance will be due in July 2005.

On July 23, 2002, the Company borrowed an additional $3,515 and issued subordinated notes to shareholders. In 2003 and 2002, the Company issuedadditional subordinated notes to its shareholders in lieu of making cash interest payments. Such notes totaled $1,188 and $946 during 2003 and 2002,respectively. The transactions are reflected as noncash financing activities on the Company’s statement of cash flows.

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The future maturities of long−term debt at December 31, 2003, are as follows:

2004 $ 4,9952005 23,3942006 812007 15,642

$ 44,112

E – COMMITMENTS AND CONTINGENCIES

1. Leases

The Company’s corporate activities are conducted from leased office facilities located in Tulsa, Oklahoma. The Company also leases certain machinery,equipment and automobiles used in its operations.

Future minimum rental payments required under noncancelable operating leases for each of the years ended December 31 are as follows:

2004 $ 802005 32006 1

$ 84

Rental expense was approximately $399, $444 and $496 for the years ended December 31, 2003, 2002 and 2001, respectively.

2. Letters of Credit

At December 31, 2003, the Company has four outstanding letters of credit in favor of various parties totaling $1,792. The letters of credit expire at varioustimes in 2004 and 2005.

3. Legal Proceedings

At December 31, 2003, the Company is party to various legal proceedings incidental to its business. Certain claims have been filed or are pending againstthe Company. In one matter, the Company has been named as a co−defendant in a lawsuit in which certain royalty owners of the Company’s co−defendantallege that the Company has been purchasing gas at below market prices. The gas involved in this legal proceeding represents a very small portion of the gaspurchased by the Company. The Company plans on defending itself vigorously. If the plaintiffs are ultimately successful, the Company believes it has theability to seek indemnification from its co−defendant. As the lawsuit is in preliminary stages, management is unable to assess the likelihood of anunfavorable outcome or estimate the amounts, if any, that will ultimately be payable. Accordingly, no accrual has been made in the Company’s balancesheet as of December 31, 2003. In the opinion of management, the resolution of various legal proceedings will not have a material effect on the financialposition or results of operations of the Company.

On November 10, 2003, the Company settled a lawsuit filed against the Company by a former shareholder. The settlement agreement requires the Companyto pay the former shareholder $1,820. At December 31, 2003, the Company has recorded an accrual of $1,820, which is included in accounts

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payable in the balance sheet and other expense in the statement of operations. The amount was paid in January 2004.

On March 9, 2004, the Oklahoma Tax Commission (OTC) filed a petition against the Company alleging that the Company underpaid gross production taxesbeginning in June 2000. The OTC is seeking a settlement of $5,000 plus interest and penalties. The Company plans on defending itself vigorously. As thelawsuit is in preliminary stages, management is unable to assess the likelihood of an unfavorable outcome or estimate the amounts, if any, that willultimately be payable. Accordingly, no accrual has been made in the Company’s balance sheet as of December 31, 2003.

4. Employment Agreements

The Company had outstanding agreements with two key employees to provide severance payments to those employees upon the occurrence of certaintriggering events, including the sale of the Company’s assets, a merger, or liquidation of the Company. Termination of both employees will result in aliability of between $142 and $229.

F — COMMON AND PREFERRED STOCK

Each share of Series A preferred stock is due quarterly dividends payable in arrears at a rate of 8% per Series A share beginning September 30, 2000. During2001, the Company paid $322 of dividends to preferred stockholders representing dividends for the first two quarters of the year. Dividends for the last twoquarters of 2001 and all of 2002 and 2003 have been declared but not paid and are recorded as dividends payable in the balance sheet. Additionally, eachshare is redeemable for cash at the option of the shareholder upon a change of control at a price equal to the original price paid for the shares plus anyaccrued and unpaid dividends. The shares of Series A preferred stock shall, with respect to dividend rights and rights upon liquidation, receive preferenceover any common stock.

1. Incentive Stock Plan and Stock Option Plan

The Company adopted the Spectrum Field Services, Inc. 2000 Incentive Stock Plan (the Plan) in order to attract, motivate and retain quality employees andto encourage valued employees to have a proprietary interest in the Company. Under the Plan, the Company may issue to selected employeesNon−Qualified Stock Options, Incentive Stock Options, Stock Appreciation Rights, Restricted Stock, Performance Units or Performance Shares, orPhantom Stock Rights. The Company has reserved 222,222 shares of common stock for issuance under the Plan.

During 2000, the Company granted key employees 211,110 shares of restricted common stock valued at $665 when issued ($3.15 per share), as determinedby management. The employees vest in the restricted stock ratably over a four−year period beginning in 2001. As vesting occurs, the Company will reversethe deferred compensation and charge compensation expense equal to the estimated fair value of the vested shares at the time of the grant.

During 2002, the Company entered into agreements with three officers holding unvested restricted common shares. According to the agreements, theCompany accelerated the vesting of some shares and repurchased all of the officers’ vested shares for $320. In addition, all remaining unvested shares werecancelled for those officers. The Company reversed $140 of deferred compensation related to the cancellation of the unvested shares in 2002 as a result.

During January 2003, the Company granted 10,000 shares of restricted common stock to an employee. The stock at the time of grant was valued at $3.15,which represented management’s estimate of the fair value of the restricted stock on the grant date. This grant vests 75% in 2003 and the remaining 25% in2004.

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The Company recorded $59, $289 and $166 of expense in 2003, 2002 and 2001, respectively, related to the vesting of restricted common stock. As ofDecember 31, 2003, 54,444 shares of restricted common stock are outstanding.

In 2002, the Company granted certain stock options to two key employees of the Company. The options will vest if a qualified triggering event occurs. Atriggering event is determined to be the earlier occurrence of (i) the date of an initial public offering of the Company’s common stock, (ii) the sale of all orsubstantially all of the assets of the Company or (iii) immediately before (a) the sale of all the outstanding common stock of the Company by the holdersthereof or (b) the merger of the Company or similar business combination with another entity in which the Company is not the survivor.

The number of options granted under the two agreements was 111,110. At December 31, 2003 and 2002, no options were vested as a triggering event hadnot occurred. The exercise price of the options is $1.00 per share. The options granted are accounted for using fixed plan accounting in accordance withAPB No. 25 as management determined that both the exercise price and the number of shares under option that will eventually vest were known at the grantdate. The intrinsic value of the options was determined to be $239 at the grant date based on management’s best estimate of the fair value of the Company’sshares at the grant date. The Company records compensation expense over the expected service period. As of December 31, 2003, the Company hasrecorded cumulative compensation expense of $74. The remaining $165 of compensation expense will be recorded over the remaining service period orwhen a triggering event occurs which causes the options to immediately vest.

The effect of Statement of Financial Standards No. 123, Accounting for Stock Based Compensation (SFAS 123) is not material. Therefore, the Company hasmade no disclosure of the pro forma net income as if SFAS 123 had been adopted. All options granted under the agreements expire after ten years.

Transactions in stock options are summarized as follows:

SharesUnderOption

ExercisePrice

Outstanding at December 31, 2001 — —Granted 111,110 $ 1.00Exercised — —Cancelled — —

Outstanding at December 31, 2002 111,110 $ 1.00Granted — —Exercised — —Cancelled — —

Outstanding at December 31, 2003 111,110 $ 1.00

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The following is a summary of stock options outstanding as of December 31, 2003:

Options Outstanding Options Exercisable

ExercisePrice

Numberof

Shares

RemainingContractual

Life

Numberof

SharesExercise

Price

$1.00 111,110 9.0 — $ 1.00

111,110

2. Phantom Unit Plan

In August 2001, the Company adopted the Employee Participation Unit Plan (the EPU Plan). Under the EPU Plan, the Company was authorized to issue167,190 phantom units to employees from time to time at the discretion of the Board of Directors. Phantom units are designed to allow holders of thephantom units to share in the value of the Company with the common shareholders. Holders of phantom units had no voting or other privileges typicallyavailable to common shareholders.

During 2002 and 2001, the Company granted 151,800 phantom units to employees. All units granted vested ratably over a five−year period. The participantsof the EPU Plan receive benefits equal to the estimated fair value of their vested units only upon normal retirement, disability or a change of control. Theform of the benefits to be paid under the EPU Plan was at the discretion of the Board of Directors.

The EPU Plan met the criteria for variable plan accounting under the provisions of APB 25. Accordingly, at each reporting period, compensation cost wasmeasured based on the estimated fair value of the vested phantom units. Compensation expense (benefit) was recorded to the extent that the fair value ofvested units increased (decreased) from the previous reporting period. The Company recorded $112 of compensation expense related to the outstandingphantom units during 2001. During 2002, the Company cancelled the EPU Plan and paid $54 to the participants of the EPU Plan, which was recorded asexpense. Additionally, the Company reversed the previously recognized compensation expense of $112.

3. Shareholders’ Commitment

On March 23, 2001, two shareholders of the Company signed an agreement committing to purchase up to $6,500 of additional debt or equity securities ifrequested to do so by the holders of the senior debt. The agreements were amended in 2003 and 2002 to $5,500 and $3,000, respectively. Such request canonly occur if an event of default (as defined in the credit agreement) has occurred and is continuing. As of December 31, 2003, this commitment was $4,500and expires on June 30, 2004.

On July 23, 2002, the Company received additional capitalization from the equity owners. The Company issued 545,529 shares of common stock ($.01 parvalue) and 2,969,471 shares of Series A preferred stock ($.01 par value) in exchange for $3,514 of cash. The Company also issued additional subordinatednotes to certain shareholders of $3,515. The Company pays a commitment fee to the shareholders related to the agreements. Fees paid to the shareholderstotaled approximately $110, $60 and $130 in 2003, 2002 and 2001.

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G – BENEFIT PLANS

The Company sponsors a defined contribution retirement plan. The Company makes discretionary matching contributions to the plan. The Companyexpensed contributions of approximately $84, $151 and $181 for the years ended December 31, 2003, 2002 and 2001, respectively.

H – CHANGE IN ACCOUNTING ESTIMATE

In December 2002, the Company began a project to replace certain gas−powered compressors with electric−powered compressors at its natural gasprocessing plant in Velma, Oklahoma. The project was completed in October 2003. In 2002, management revised the estimated useful lives of the previousgas−powered compressors to reflect usage of those assets through July 2003. The Company treated the change in useful life as a change in accountingestimate. Accordingly, the Company revised its depreciation calculation on a prospective basis from the date the project was probable, which was November30, 2002. As a result, the Company recorded additional depreciation expense of $1,342 during 2002 and depreciated the remaining net book value of $9,868in 2003. Additionally, the Company excelerated depreciation in 2003 on certain other compressors that were not originally part of this project. This resultedin additional depreciation of $497.

In April 2003, the Company began a project to replace the Sulphur Recovery Unit (SRU) at its natural gas processing plant in Velma, Oklahoma.Management revised the estimated useful life of the SRU to reflect usage of the asset through October 2003. The Company treated the change in useful lifeas a change in accounting estimate. As a result, the Company depreciated the remaining net book value of $3,287 in 2003. The project was completed inMarch 2004.

I – RELATED PARTY TRANSACTIONS

During 2003, the Company had sales to an affiliate of approximately $687, which is recorded as accrued sales at December 31, 2003. During 2002, therewere no sales to affiliates.

During part of 2001, one of the Company’s primary customers was a shareholder. All transactions between the Company and the shareholder were atprevailing market rates. During 2001, the Company had sales to the shareholder of approximately $15,000. At December 31, 2001, no amounts were duefrom the shareholder.

During 2003, 2002 and 2001, the Company had sales of condensate to an affiliate of approximately $453, $1,663 and $2,100, respectively.

J – SUBSEQUENT EVENT

On June 10, 2004, the Company, along with Energy Spectrum Partners II LP, Energy Spectrum Partners III LP and other various sellers, entered into aSecurities Purchase Agreement with Atlas Pipeline Operating Partnership, L.P. to sell the outstanding capital stock of the Company for a total purchase priceof $104,000 adjusted for changes in net working capital, less amounts owed for long−term debt and adjusted for other transaction costs.

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APPENDIX A

AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF ATLAS PIPELINE HOLDINGS, L.P.

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ATLAS PIPELINE HOLDINGS, L.P.

3,600,000 Common Units

Representing Limited Partner Interests

PROSPECTUS

, 2006

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PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution. Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distributionof the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee, the amounts set forthbelow are estimates.

SEC registration fee $ 11,074.50

NASD filing fee 10,436.00

Printing and engraving expenses 275,489.50

Fees and expenses of legal counsel 425,000.00

Accounting fees and expenses 400,000.00

Transfer agent and registrar fees 3,000.00

New York Stock Exchange listing fee 150,000.00

Structuring Fee *

Miscellaneous

Total $

*To be filed by amendment.

Item 14. Indemnification of Officers and Members of Our Board of Directors. The section of the prospectus entitled “The Partnership Agreement of Atlas Pipeline Holdings, L.P.–Indemnification” discloses that we will generallyindemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar eventsand is incorporated herein by this reference. Reference is also made to Section __ of the Underwriting Agreement filed as an exhibit to this registration statementin which Atlas and certain of its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933,as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forthin the partnership agreement, Section 17−108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnifyand hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15. Exhibits. The following documents are filed as exhibits to this registration statement:

Exhibit

Number Description

1.1* — Form of Underwriting Agreement3.1* — Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P.3.2* — Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P.3.3* — Certificate of Formation of Atlas Pipeline Holdings GP, LLC3.4* — Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC3.5* — Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.3.6* — Form of Contribution Agreement5.1* — Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered8.1* — Opinion of Vinson & Elkins L.L.P. relating to tax matters10.1* — Credit Agreement among Atlas America, Inc., Resource America, Inc., Wachovia Bank, National Association, and other

banks party thereto, dated March 12, 200410.2* — First Amendment to March 12, 2004 Credit Agreement, dated July 10, 200410.3* — Revolving Credit and Term Loan Agreement, dated as of April 14, 2005 among Atlas Pipeline Partners, L.P., Wachovia

Bank, National Association and the other parties thereto10.4* — First Amendment to Revolving Credit and Term Loan Agreement, dated as of April 14, 2005, among Atlas Pipeline Partners,

L.P., Wachovia Bank National Association and the other parties thereto10.5* — Master Natural Gas Gathering Agreement among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, Atlas

America, Inc., Resource Energy, Inc. and Viking Resources Corporation10.6* — Omnibus Agreement among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, Atlas America, Inc.,

Resource Energy, Inc. and Viking Resources Corporation21.1* — List of Subsidiaries of Atlas Pipeline Holdings, L.P.23.1 — Consent of Grant Thornton LLP23.2 — Consent of Ernst & Young LLP23.3* — Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)


23.4* — Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)24.1* — Powers of Attorney (contained on page II−3)

* To be filed by amendment.

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Item 16. Undertakings. The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in suchdenominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrantpursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission suchindemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification againstsuch liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successfuldefense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, theregistrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the questionwhether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registrationstatement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under theSecurities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post−effective amendment that contains a form of prospectus shall bedeemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to bethe initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Atlas America or itsaffiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Atlas America or its affiliates for the fiscal year completed, showing theamount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10−K for the first full fiscal year of operations of thepartnership.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalfby the undersigned, thereunto duly authorized, in the Commonwealth of Philadelphia, State of Pennsylvania, on January 12, 2006.


By:Atlas PipelineHoldings GP, LLC,its general partner

By: /s/ Edward E. Cohen

Name: Edward E. CohenTitle: Chairman of the Boardand Chief Executive Officer

KNOWN ALL PERSONS BY THESE PRESENTS, that the persons whose signatures appear below, constitute and appoint Edward E. Cohen and MatthewA. Jones, and each of them, as their true and lawful attorneys−in−fact and agents, with full power of substitution and resubstitution, for them and in their names,places and steads, in any and all capacities, to sign the Registration Statement to be filed in connection with the public offering of common units representinglimited partnership interests of Atlas Pipeline Holdings, L.P., and any and all amendments (including post−effective amendments) to the Registration Statement,and any subsequent registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibitsthereto, and the other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys−in−fact and agents, andeach of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to allintents and purposes as they might or could do in person, hereby ratifying and conforming all that said attorneys−in−fact and agents, or any of them, or their orhis or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in thecapacities and on the dates indicated.

Signature Title Date

/s/ Edward E. Cohen Chairman of the Board and Chief Executive Officer 1/12/2006

Edward E. Cohen

/s/ Jonathan Z. Cohen Vice Chairman of the Board 1/12/2006

Jonathan Z. Cohen

/s/ Robert R. Firth President 1/12/2006

Robert R. Firth

/s/ Matthew A. Jones Chief Financial Officer 1/12/2006

Matthew A. Jones

/s/ Lisa Washington Chief Legal Officer and Secretary 1/12/2006

Lisa Washington

/s/ Steven J. Doherty Director 1/12/2006

Steven J. Doherty

/s/ William G. Karis Director 1/12/2006

William G. Karis


/s/ Harvey G. Magarick Director 1/12/2006

Harvey G. Magarick

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INDEX

Exhibit

Number Description

1.1* — Form of Underwriting Agreement 3.1* — Certificate of Limited Partnership of Atlas Pipeline Holdings, L.P. 3.2* — Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Holdings, L.P. 3.3* — Certificate of Formation of Atlas Pipeline Holdings GP, LLC 3.4* — Amended and Restated Limited Liability Company Agreement of Atlas Pipeline Holdings GP, LLC3.5* — Second Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P.3.6* — Form of Contribution Agreement5.1* — Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered8.1* — Opinion of Vinson & Elkins L.L.P. relating to tax matters10.1* — Credit Agreement among Atlas America, Inc., Resource America, Inc., Wachovia Bank, National Association, and other

banks party thereto, dated March 12, 200410.2* — First Amendment to March 12, 2004 Credit Agreement, dated July 10, 200410.3* — Revolving Credit and Term Loan Agreement, dated as of April 14, 2005 among Atlas Pipeline Partners, L.P., Wachovia

Bank, National Association and the other parties thereto10.4* — First Amendment to Revolving Credit and Term Loan Agreement, dated as of April 14, 2005, among Atlas Pipeline Partners,

L.P., Wachovia Bank National Association and the other parties thereto10.5* — Master Natural Gas Gathering Agreement among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, Atlas

America, Inc., Resource Energy, Inc. and Viking Resources Corporation10.6* — Omnibus Agreement among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, Atlas America, Inc.,

Resource Energy, Inc. and Viking Resources Corporation21.1* — List of Subsidiaries of Atlas Pipeline Holdings, L.P.23.1 — Consent of Grant Thornton LLP23.2 — Consent of Ernst & Young LLP23.3* — Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)23.4* — Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)24.1* — Powers of Attorney (contained on page II−3)

* To be filed by amendment.


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CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated December 21, 2005 accompanying the consolidated financial statements of Atlas Pipeline Partners GP, LLC as of December 31,2004 and 2003 and for each of the three years in the period ended December 31, 2004; our report dated January 3, 2006 accompanying the balance sheet of AtlasPipeline Holdings, L.P. as of December 31, 2005; our report dated January 3, 2006 accompanying the balance sheet of Atlas Pipeline Holdings GP, LLC as ofDecember 31, 2005; our report dated April 25, 2005 accompanying the financial statements of ETC Oklahoma Pipeline, Ltd. as of August 31, 2004 and 2003 andfor the year ended August 31, 2004 and the eleven month period ended August 31, 2003; our report dated April 25, 2005 accompanying the financial statementsof the Elk City System (a division of the Aquila Gas Pipeline Corporation) for the year ended September 30, 2002; our report dated May 17, 2004, except withrespect to the matters discussed in Note J, as to which the date is June 10, 2004, accompanying the financial statements of Spectrum Field Services, Inc. as ofDecember 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003 contained in the Registration Statement on Form S−1 forAtlas Pipeline Holdings, L.P. We consent to the use of the aforementioned reports in the Registration Statement and Prospectus, and to the use of our name as itappears under the caption “Experts.”




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CONSENT OF INDEPENDENT AUDITORS

We consent to the reference to our firm under the caption “Experts” and to the use of our report dated October 31, 2005, with respect to the consolidated financialstatements of Enogex Arkansas Pipeline Corporation at December 31, 2004 and 2003, and for each of the two years in the period ended December 31, 2004,included in the Registration Statement on Form S−1 and related Prospectus of Atlas Pipeline Holdings, L.P. for the registration of 3,600,000 units of its commonunits.

/s/ Ernst & Young LLP

Oklahoma City, OklahomaJanuary 9, 2006

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